Systems and processes for upgrading and converting crude oil to petrochemicals through steam cracking

ABSTRACT

A process for upgrading a hydrocarbon feed, such as crude oil or other heavy oils, may include hydrotreating a hydrocarbon feed in a hydrotreating unit to produce a hydrotreated effluent that includes asphaltenes, coke precursors, or both. The process further includes hydrocracking the hydrotreated effluent in a hydrocracking unit to produce a hydrocracked effluent, adsorbing at least a portion of the asphaltenes, coke precursors, or both, from the hydrotreated effluent, the hydrocracked effluent, or both, separating the hydrocracked effluent into at least an upgraded lesser-boiling effluent and a greater-boiling effluent in a hydrocracked effluent separation system, and steam cracking the upgraded lesser-boiling effluent to produce olefins, aromatic compounds, or combinations of these. The process may further include recycling the greater boiling effluent back to the hydrotreating unit and hydrocracking a middle distillate effluent from the hydrocracked effluent separation system. Systems for conducting the processes are also disclosed.

CROSS-REFERENCE TO RELATED APPLICATION

This application is a continuation application of U.S. patentapplication Ser. No. 16/720,240 filed Dec. 19, 2019, the entiredisclosure of which is incorporated by reference in the presentdisclosure.

BACKGROUND Field

The present disclosure relates to systems and processes for processingpetroleum-based materials, in particular, systems and processes forupgrading and converting crude oil to petrochemical products andintermediates through hydroprocessing and steam cracking.

Technical Background

Petrochemical feeds, such as crude oils, can be converted to chemicalproducts and intermediates such as olefins and aromatic compounds, whichare basic intermediates for a large portion of the petrochemicalindustry. The worldwide increasing demand for light olefins and aromaticcompounds remains a major challenge for many integrated refineries. Inparticular, the production of some valuable light olefins such asethylene, propene, and butene has attracted increased attention as pureolefin streams are considered the building blocks for polymer synthesis.Additionally, aromatic compounds such as benzene, toluene, ethylbenzene,and xylenes are valuable intermediates for synthesizing polymers andother organic compounds as well as for fuel additives.

Olefins and aromatic compounds can be produced through stream crackingof hydrocarbon feeds, such as natural gas, naphtha, or atmospheric gasoil (AGO). In order to obtain greater yields of olefins and aromaticcompounds, suitable feedstocks for steam cracking processes aregenerally rich in paraffinic hydrocarbons with lesser concentrations ofaromatic compounds, which may reduce the formation of undesiredby-products and coke formation during steam cracking. Crude oil andother heavy oils are increasingly being considered as feedstocks forsteam cracking processes. While crude oil and other heavy oils may be apotential feedstock, the concentrations of metal, nitrogen, sulfur,asphaltenes, polyaromatic compounds, and other large organic moleculesin crude oil and other heavy oils can contribute to contamination ofeffluent streams form the steam cracking process and production of coke,which can buildup on downstream equipment. When using crude oil andother heavy oils as a feed stock for steam cracking, up to 30 weightpercent of the crude oil comprising the constituents having boilingpoint temperatures greater than 540 degrees Celsius must be rejected andremoved from the system to reduce coke formation and ensure smoothoperation of the steam cracking system.

SUMMARY

Accordingly, there is an ongoing need for systems and processes forincreasing the yield of olefins and aromatic compounds from a steamcracking process when using crude oil or other heavy oils for thehydrocarbon feed. The systems and processes of the present disclosuremay provide for increased yield of olefins and aromatic compounds fromsteam cracking by subjecting a crude oil or heavy oil to hydroprocessingto remove trace impurities and upgrade the crude oil or heavy oil toproduce an upgraded lesser-boiling effluent having increasedconcentrations of paraffinic compounds. The systems and methods of thepresent disclosure may increase the yields of olefins and aromaticcompounds from steam cracking of crude oil and other heavy oils byenabling a greater portion of the crude oil to be converted to steamcrackable constituents, such as paraffins and other hydrocarbons havingboiling point temperatures less than or equal to 180° C., for feeding tothe steam cracking process. Thus, a greater portion of the constituentshaving boiling point temperatures greater than 540° C. can be convertedto olefins and aromatic compounds rather than being rejected and removedprior to steam cracking.

The hydroprocessing may include hydrotreating the crude oil or heavy oilwith hydrotreating catalysts in a hydrotreating system to removeimpurities such as sulfur, nitrogen, and metals, and to de-aromatizepolyaromatic compounds and asphaltenes. Hydroprocessing may furtherinclude hydrocracking the hydrotreated effluent in the presence of ahydrocracking catalyst in a hydrocracking unit to convert at least aportion of the remaining aromatic and polyaromatic compounds in thehydrotreated effluent to paraffinic compounds. The resultinghydrocracked effluent may have an increased concentration ofhydrocarbons having boiling point temperatures less than or equal to180° C. compared to the hydrotreated effluent. The hydrocracked effluentis then separated in a hydrocracked effluent separation system toproduce at least the upgraded lesser-boiling effluent and agreater-boiling effluent. The upgraded lesser-boiling effluent may bepassed to the steam cracking system as the feed for steam cracking. Thegreater-boiling effluent may be passed back to the hydroprocessingsystem, such as back to the hydrotreating unit, for further conversionof greater-boiling constituents to hydrocarbons having boiling pointtemperatures less than or equal to 180° C., which may further increasethe yield of olefins and aromatic compounds from the steam crackingsystem. The hydrocracked effluent separation system may further separatea middle-boiling effluent, which may be further hydrocracked in asecondary hydrocracking unit.

During hydrotreating of the crude oil or heavy oils, the severeconditions may breakdown oil fractions that stabilize and solubilizecoke precursors, such as asphaltene compounds. Destruction of thestabilization system for the asphaltenes and other coke precursors mayresult in precipitation of asphaltenes and other coke precursors fromthe hydrotreated effluent. The precipitated asphaltenes and other cokeprecursors may deposit on downstream hydrocracking catalysts, causingdeactivation of the hydrocracking catalysts. Deactivation of thehydrocracking catalysts caused by deposition of asphaltenes and coke onthe hydrocracking catalyst may reduce the yield of paraffinic compoundsfrom the hydrocracking process and cause problems with catalyst life andsmooth operation of the hydrocracking process. Even at smallconcentrations, such as less than 0.5 weight percent, asphaltenes andother coke precursors can cause significant deactivation ofhydrocracking catalysts.

To reduce deactivation of hydrocracking catalysts and deposition ofasphaltenes and coke on process equipment downstream of thehydrotreating unit, the systems of the present disclosure may include anadsorption unit operable to remove at least a portion of the asphaltenesand other coke precursors from the system. Processes of the presentdisclosure may include passing one or more of the process effluents,such as the hydrotreated effluent, the hydrocracked effluent, or otherstream, through the adsorption unit to remove the asphaltene compoundsand other coke precursors. The systems and processes of the presentdisclosure may increase the yield of olefins and aromatic compounds fromsteam cracking crude oil or other heavy oils by removing impurities fromthe crude oil or heavy oil and converting a greater portion of thehydrocarbons in the crude oil or heavy oil to hydrocarbons havingboiling point temperatures less than or equal to 180° C. Additionally,the systems and processes of the present disclosure may improveefficient operation of the hydrocracking unit and steam cracking systemby removing asphaltenes and other coke precursors from the processeffluent streams.

According to at least one aspect of the present disclosure, a processfor upgrading a hydrocarbon feed may include hydrotreating a hydrocarbonfeed to produce a hydrotreated effluent, where the hydrotreated effluentmay comprise asphaltenes, coke precursors, or both. The process mayfurther include hydrocracking the at least a portion of the hydrotreatedeffluent to produce a hydrocracked effluent and adsorbing at least aportion of the asphaltenes, coke precursors, or both, from thehydrotreated effluent, the hydrocracked effluent, or both. The processmay further include separating the hydrocracked effluent into at leastan upgraded lesser-boiling effluent and a greater-boiling effluent andsteam cracking the upgraded lesser-boiling effluent to produce olefins,aromatic compounds, or combinations of these.

According to another aspect of the present disclosure, a process forupgrading a hydrocarbon feed may include contacting the hydrocarbon feedwith at least one hydrotreating catalyst in the presence of hydrogen inat least one hydrotreating zone. The hydrocarbon feed may comprise wholecrude or desalted whole crude and the contacting may remove at least oneof metals, sulfur compounds, nitrogen compounds, or combinations ofthese to produce a hydrotreated effluent. The process may furtherinclude contacting the hydrotreated effluent with a hydrocrackingcatalyst in the presence of hydrogen, where contacting with thehydrocracking catalyst may cause at least a portion of hydrocarbons inthe hydrotreated effluent to undergo hydrocracking reactions to producea hydrocracked effluent. The process may further include contacting atleast a portion of the hydrotreated effluent or at least a portion ofthe hydrocracked effluent with an adsorbent in an adsorption unit. Theadsorbent may remove at least a portion of asphaltenes, coke precursors,or both, from the portion of the hydrotreated effluent or the portion ofthe hydrocracked effluent. The process may further include passing thehydrocracked effluent to a hydrocracked effluent separation systemoperable to separate the hydrocracked effluent into at least an upgradedlesser-boiling effluent and a greater boiling effluent and contactingthe upgraded lesser-boiling effluent with steam in a steam cracking zonemaintained at a steam cracking temperature. Contacting the upgradedlesser-boiling effluent with steam at the steam cracking temperature maycause at least a portion of the upgraded lesser-boiling effluent toundergo thermal cracking to produce a steam cracking effluent comprisingolefins, aromatic compounds, or both.

According to still another aspect of the present disclosure, a systemfor processing crude oil may include a hydrotreating unit comprising atleast one hydrotreating catalyst. The hydrotreating unit may be operableto contact the crude oil with the at least one hydrotreating catalyst.Contact with the hydrotreating catalyst may upgrade the crude oil to ahydrotreated effluent having a reduced concentration of at least one ofnitrogen, sulfur, metals, aromatic compounds, or combinations of these.The system may further include a hydrocracking unit disposed downstreamof the hydrotreating unit and comprising a hydrocracking catalyst. Thehydrocracking unit may be operable to contact at least a portion of thehydrotreated effluent with the hydrocracking catalyst at conditionssufficient to convert at least a portion of the hydrotreated effluent toproduce a hydrocracked effluent comprising hydrocarbons having a boilingpoint temperature less than or equal to 180° C. The system may furtherinclude an adsorption unit downstream of the hydrotreating unit or thehydrocracking unit. The adsorption unit may be operable to contact thehydrotreated effluent or the hydrocracked effluent with an adsorbentcapable of adsorbing asphaltenes, coke precursors, or both from thehydrotreated effluent or the hydrocracked effluent. The system mayfurther include a hydrocracked effluent separation system downstream ofthe hydrocracking unit. The hydrocracked effluent separation system maybe operable to separate at least a portion of the hydrocracked effluentinto at least an upgraded lesser-boiling effluent and a greater-boilingeffluent. The system may further include a steam cracking systemdownstream of the hydrocracked effluent separation system. The steamcracking system may be operable to convert at least a portion of theupgraded lesser-boiling effluent to produce olefins, aromatic compounds,or both.

Additional features and advantages of the technology described in thisdisclosure will be set forth in the detailed description which follows,and in part will be readily apparent to those skilled in the art fromthe description or recognized by practicing the technology as describedin this disclosure, including the detailed description which follows,the claims, as well as the appended drawings.

BRIEF DESCRIPTION OF THE DRAWINGS

The following detailed description of specific embodiments of thepresent disclosure can be best understood when read in conjunction withthe following drawings, where like structure is indicated with likereference numerals and in which:

FIG. 1 schematically depicts a generalized flow diagram of a system forupgrading heavy oils to olefins, aromatic compounds, or both, accordingto one or more embodiments shown and described in this disclosure;

FIG. 2 schematically depicts a generalized flow diagram of ahydrocracked effluent separation system of the system of FIG. 1,according to one or more embodiments shown and described in thisdisclosure;

FIG. 3 schematically depicts a generalized flow diagram of a steamcracking system of the system of FIG. 1, according to one or moreembodiments shown and described in this disclosure;

FIG. 4 schematically depicts a generalized flow diagram of anotherembodiment of a system for upgrading heavy oils to olefins, aromaticcompounds, or both, according to one or more embodiments shown anddescribed in this disclosure;

FIG. 5 schematically depicts a generalized flow diagram of yet anotherembodiment of a system for upgrading heavy oils to olefins, aromaticcompounds, or both, according to one or more embodiments shown anddescribed in this disclosure; and

FIG. 6 schematically depicts a generalized flow diagram of still anothersystem for upgrading heavy oils to olefins, aromatic compounds, or both,according to one or more embodiments shown and described in thisdisclosure.

For the purpose of describing the simplified schematic illustrations anddescriptions of FIGS. 1-6, the numerous valves, temperature sensors,electronic controllers and the like that may be employed and well knownto those of ordinary skill in the art of certain chemical processingoperations are not included. Further, accompanying components that areoften included in chemical processing operations, such as, for example,air supplies, heat exchangers, surge tanks, or other related systems arenot depicted. It would be known that these components are within thespirit and scope of the present embodiments disclosed. However,operational components, such as those described in the presentdisclosure, may be added to the embodiments described in thisdisclosure.

It should further be noted that arrows in the drawings refer to processstreams. However, the arrows may equivalently refer to transfer lineswhich may serve to transfer process steams between two or more systemcomponents. Additionally, arrows that connect to system componentsdefine inlets or outlets in each given system component. The arrowdirection corresponds generally with the major direction of movement ofthe materials of the stream contained within the physical transfer linesignified by the arrow. Furthermore, arrows which do not connect two ormore system components signify a product stream which exits the depictedsystem or a system inlet stream which enters the depicted system.Product streams may be further processed in accompanying chemicalprocessing systems or may be commercialized as end products. Systeminlet streams may be streams transferred from accompanying chemicalprocessing systems or may be non-processed feedstock streams. Somearrows may represent recycle streams, which are effluent streams ofsystem components that are recycled back into the system. However, itshould be understood that any represented recycle stream, in someembodiments, may be replaced by a system inlet stream of the samematerial, and that a portion of a recycle stream may exit the system asa system product.

Additionally, arrows in the drawings may schematically depict processsteps of transporting a stream from one system component to anothersystem component. For example, an arrow from one system componentpointing to another system component may represent “passing” a systemcomponent effluent to another system component, which may include thecontents of a process stream “exiting” or being “removed” from onesystem component and “introducing” the contents of that product streamto another system component.

It should be understood that two or more process streams are “mixed” or“combined” when two or more lines intersect in the schematic flowdiagrams of FIGS. 1-6. Mixing or combining may also include mixing bydirectly introducing both streams into a like reactor, separationdevice, or other system component. For example, it should be understoodthat when two streams are depicted as being combined directly prior toentering a separation unit or reactor, that in some embodiments thestreams could equivalently be introduced into the separation unit orreactor and be mixed in the reactor.

Reference will now be made in greater detail to various embodiments,some embodiments of which are illustrated in the accompanying drawings.Whenever possible, the same reference numerals will be used throughoutthe drawings to refer to the same or similar parts.

DETAILED DESCRIPTION

The present disclosure is directed to systems and methods for upgradingheavy oils, such as crude oil, to produce more valuable chemicalintermediates, such as olefins and aromatic compounds, for example.Referring to FIG. 1, one embodiment of a system 100 for upgrading ahydrocarbon feed 102 comprising crude oil or other heavy oil isschematically depicted. The system 100 includes a hydrotreating unit 110comprising at least one hydrotreating catalyst and operable to contactthe crude oil or other heavy oil with the at least one hydrotreatingcatalyst, a hydrocracking unit 130 disposed downstream of thehydrotreating unit 110 and comprising a hydrocracking catalyst, and anadsorption unit 120 downstream of the hydrotreating unit 110 or thehydrocracking unit 130 and operable to contact a hydrotreated effluent112 or a hydrocracked effluent 134 with an adsorbent capable ofadsorbing asphaltenes, coke precursors, or both. The system 100 furtherincludes a hydrocracked effluent separation system 140 downstream of thehydrocracking unit 130 and a steam cracking system 160 downstream of thehydrocracked effluent separation system 140. The system 100 may furtherinclude a greater-boiling effluent recycle 149 operable to pass agreater-boiling effluent 148 from the hydrocracked effluent separationsystem 140 back to the hydrotreating unit 110. Referring to FIG. 4, thesystem 100 may further include a secondary hydrocracking unit 190operable to contact a middle distillate effluent 146 from thehydrocracked effluent separation system 140 with a secondaryhydrocracking catalyst. The system 100 may be operable to upgradehydrocarbons in the crude oil or other heavy oil into an upgradedlesser-boiling effluent 144 comprising hydrocarbons having boiling pointtemperatures less than 180° C. and then steam cracking this upgradedlesser-boiling effluent 144 to produce olefins, aromatic compounds, orboth. The system 100 may further include passing a pyrolysis oil 168from the steam cracking system 160 back to the hydrocracked effluentseparation system 140 for further conversion of constituents of thecrude oil or heavy oil to the upgraded lesser-boiling effluent 144.

Referring again to FIG. 1, a process for upgrading a hydrocarbon feed102, such as the crude oil or other heavy oil, includes hydrotreatingthe hydrocarbon feed 102 to produce a hydrotreated effluent 112, wherethe hydrotreated effluent 112 may include asphaltenes, coke precursors,or both. The process further includes hydrocracking at least a portionof the hydrotreated effluent 112 to produce a hydrocracked effluent 134and adsorbing at least a portion of the asphaltenes, coke precursors, orboth, from the hydrotreated effluent 112, the hydrocracked effluent 134,or both. The process further includes separating the hydrocrackedeffluent 134 into at least an upgraded lesser-boiling effluent 144 and agreater-boiling effluent 148 and steam cracking the upgradedlesser-boiling effluent 144 to produce olefins, aromatic compounds, orcombinations of these. The upgraded lesser-boiling effluent 144 mayinclude hydrocarbons having boiling point temperatures less than orequal to 180° C. The process may further include recycling thegreater-boiling effluent 148 to the hydrotreating process andhydrotreating the greater-boiling effluent 148. The process may furtherinclude hydrocracking a middle distillate effluent 146 separated fromthe hydrocracked effluent 134. The process may further include passing apyrolysis oil 168 from the steam cracking process back into the systemfor further conversion of hydrocarbons to the upgraded lesser-boilingeffluent 144.

The systems and processes of the present disclosure may enable crude oiland heavy oils to be used as the hydrocarbon feed for production ofolefins and aromatic compounds through steam cracking. The systems andprocesses of the present disclosure may also enable crude oil and otherheavy oils to be introduced directly to the process without upstreamseparation processes, such as fractionation columns, that can be costlyto construct and operate. The systems and processes of the presentdisclosure may reduce deactivation of hydrocracking catalysts byremoving asphaltenes and other coke precursors from the system, whichmay improve operation of the system. The systems and processes of thepresent disclosure may also increase conversion of hydrocarbons in thecrude oil or other heavy oil to the upgraded lesser-boiling effluent,which can then be used as a feed for the steam cracking process. Thismay result in increased yield of olefins, aromatic compounds, or bothfrom the crude oil or other heavy oil compared to other steam crackingprocesses, among other features.

As used in this disclosure, a “reactor” refers to any vessel, container,or the like, in which one or more chemical reactions may occur betweenone or more reactants optionally in the presence of one or morecatalysts. For example, a reactor may include a tank or tubular reactorconfigured to operate as a batch reactor, a continuous stirred-tankreactor (CSTR), or a plug flow reactor. Example reactors include packedbed reactors such as fixed bed reactors, and fluidized bed reactors. Oneor more “reaction zones” may be disposed within a reactor. As used inthis disclosure, a “reaction zone” refers to an area where a particularreaction takes place in a reactor. For example, a packed bed reactorwith multiple catalyst beds may have multiple reaction zones, where eachreaction zone is defined by the area of each catalyst bed.

As used in this disclosure, a “separation unit” refers to any separationdevice that at least partially separates one or more chemicals in amixture from one another. For example, a separation unit may selectivelyseparate different chemical species from one another, forming one ormore chemical fractions. Examples of separation units include, withoutlimitation, distillation columns, fractionators, flash drums, knock-outdrums, knock-out pots, centrifuges, filtration devices, traps,scrubbers, expansion devices, membranes, solvent extraction devices,high-pressure separators, low-pressure separators, and the like. Itshould be understood that separation processes described in thisdisclosure may not completely separate all of one chemical consistentfrom all of another chemical constituent. It should be understood thatthe separation processes described in this disclosure “at leastpartially” separate different chemical components from one another, andthat even if not explicitly stated, it should be understood thatseparation may include only partial separation. As used in thisdisclosure, one or more chemical constituents may be “separated” from aprocess stream to form a new process stream. Generally, a process streammay enter a separation unit and be divided or separated into two or moreprocess streams of desired composition.

As used in this disclosure, the term “fractionation” may refer to aprocess of separating one or more constituents of a composition in whichthe constituents are divided from each other during a phase change basedon differences in properties of each of the constituents. As an example,as used in this disclosure, “distillation” refers to separation ofconstituents of a liquid composition based on differences in the boilingpoint temperatures of constituents of a composition.

Further, in some separation processes, a “lesser-boiling effluent” and a“greater-boiling effluent” may separately exit the separation unit. Ingeneral, the lesser-boiling effluent has a lesser boiling pointtemperature than the greater-boiling effluent. Some separation systemsmay produce a “middle-boiling effluent,” which may include constituentshaving boiling point temperatures between the boiling point temperaturesof the lesser-boiling effluent and the greater-boiling effluent. Themiddle-boiling effluent may be referred to as a middle distillate. Someseparation systems may be operable to produce a plurality of streams,each with a different boiling point range. It should be additionallyunderstood that where only one separation unit is depicted in a figureor described, two or more separation units may be employed to carry outthe identical or substantially identical separations. For example, wherea distillation column with multiple outlets is described, it iscontemplated that several separators arranged in series may equallyseparate the feed stream and such embodiments are within the scope ofthe presently described embodiments.

As used in this disclosure, the terms “upstream” and “downstream” mayrefer to the relative positioning of unit operations with respect to thedirection of flow of the process streams. A first unit operation of asystem may be considered “upstream” of a second unit operation ifprocess streams flowing through the system encounter the first unitoperation before encountering the second unit operation. Likewise, asecond unit operation may be considered “downstream” of the first unitoperation if the process streams flowing through the system encounterthe first unit operation before encountering the second unit operation.

As used in the present disclosure, passing a stream or effluent from oneunit “directly” to another unit may refer to passing the stream oreffluent from the first unit to the second unit without passing thestream or effluent through an intervening reaction system or separationsystem that substantially changes the composition of the stream oreffluent. Heat transfer devices, such as heat exchangers, preheaters,coolers, condensers, or other heat transfer equipment, and pressuredevices, such as pumps, pressure regulators, compressors, or otherpressure devices, are not considered to be intervening systems thatchange the composition of a stream or effluent. Combining two streams oreffluents together also is not considered to comprise an interveningsystem that changes the composition of one or both of the streams oreffluents being combined.

As used in this disclosure, the term “end boiling point” or “EBP” of acomposition may refer to the temperature at which the greatest boilingtemperature constituents of the composition transition from the liquidphase to the vapor phase.

As used in this disclosure, the term “effluent” may refer to a streamthat is passed out of a reactor, a reaction zone, or a separation unitfollowing a particular reaction or separation. Generally, an effluenthas a different composition than the stream that entered the separationunit, reactor, or reaction zone. It should be understood that when aneffluent is passed to another system unit, only a portion of that systemstream may be passed. For example, a slip stream may carry some of theeffluent away, meaning that only a portion of the effluent may enter thedownstream system unit. The term “reaction effluent” may moreparticularly be used to refer to a stream that is passed out of areactor or reaction zone.

As used in this disclosure, a “catalyst” refers to any substance whichincreases the rate of a specific chemical reaction. Catalysts describedin this disclosure may be utilized to promote various reactions, suchas, but not limited to, hydrodemetalization, hydrodesulfurization,hydrodenitrogenation, hydrodearomatization, hydrocracking, cracking,aromatic cracking, or combinations thereof.

As used in this disclosure, “cracking” generally refers to a chemicalreaction where a molecule having carbon-carbon bonds is broken into morethan one molecule by the breaking of one or more of the carbon-carbonbonds; where a compound including a cyclic moiety, such as an aromatic,is converted to a compound that does not include a cyclic moiety; orwhere a molecule having carbon-carbon double bonds are reduced tocarbon-carbon single bonds. Some catalysts may have multiple forms ofcatalytic activity, and calling a catalyst by one particular functiondoes not render that catalyst incapable of being catalytically activefor other functionality. As used throughout the present disclosure,“hydrocracking” may refer to catalytic cracking of hydrocarbonsconducted in the presence of hydrogen.

As used throughout the present disclosure, the term “butene” or“butenes” refer to one or more than one of 1-butene, trans-2-butene,cis-2-butene, isobutene, or mixtures of these isomers. As usedthroughout the present disclosure, the term “normal butenes” may referto one or more than one of 1-butene, trans-2-butene, cis-2-butene, ormixtures of these isomers, and does not include isobutene. As usedthroughout the present disclosure, the term “2-butene” may refer totrans-2-butene, cis-2-butene, or a mixture of these two isomers.

As used throughout the present disclosure, the term “xylenes,” when usedwithout a designation of the isomer, such as the prefix para, meta, orortho (or letters p, m, and o, respectively), may refer to one or moreof meta-xylene, ortho-xylene, para-xylene, and mixtures of these xyleneisomers.

As used throughout the present disclosure, the term “crude oil” or“whole crude oil” may refer to crude oil received directly from an oilfield or from a desalting unit without having any fraction separated bydistillation.

It should be understood that the reactions promoted by catalysts asdescribed in this disclosure may remove a chemical constituent, such asonly a portion of a chemical constituent, from a process stream. Forexample, a hydrodemetalization (HDM) catalyst may be present in anamount sufficient to promote a reaction that removes a portion of one ormore metals from a process stream. A hydrodenitrogenation (HDN) catalystmay be present in an amount sufficient to promote a reaction thatremoves a portion of the nitrogen present in a process stream. Ahydrodesulfurization (HDS) catalyst may be present in an amountsufficient to promote a reaction that removes a portion of the sulfurpresent in a process stream. A hydrodearomatization (HDA) catalyst maybe present in an amount sufficient to promote a reaction that convertsaromatics to naphthalenes, paraffinic compounds, or both. Ahydrocracking catalyst may be present in an amount sufficient to promotea reaction that converts aromatics, which are hard to convert in thesteam cracking system, to naphthalenes, paraffinic compounds, or both,which are easier to convert in the steam cracking system. It should beunderstood that, throughout this disclosure, a particular catalyst maynot be limited in functionality to the removal, conversion, or crackingof a particular chemical constituent or moiety when it is referred to ashaving a particular functionality. For example, a catalyst identified inthis disclosure as an HDN catalyst may additionally providehydrodearomatization functionality, hydrodesulfurization functionality,or both.

It should further be understood that streams may be named for thecomponents of the stream, and the component for which the stream isnamed may be the major component of the stream (such as comprising from50 wt. %, from 70 wt. %, from 90 wt. %, from 95 wt. %, from 99 wt. %,from 99.5 wt. %, or even from 99.9 wt. % of the contents of the streamto 100 wt. % of the contents of the stream). It should also beunderstood that components of a stream are disclosed as passing from onesystem component to another when a stream comprising that component isdisclosed as passing from that system component to another. For example,a disclosed “hydrogen stream” passing to a first system component orfrom a first system component to a second system component should beunderstood to equivalently disclose “hydrogen” passing to the firstsystem component or passing from a first system component to a secondsystem component.

Referring to FIG. 1, a system 100 of the present disclosure forconverting a hydrocarbon feed 102 to olefins, aromatic compounds, orboth, through hydroprocessing and steam cracking is schematicallydepicted. The system 100 may include the hydrotreating unit 110, thehydrocracking unit 130 downstream of the hydrotreating unit 110, thehydrocracked effluent separation system 140 downstream of thehydrocracking unit 130, and the steam cracking system 160 downstream ofthe hydrocracked effluent separation system 140. The system 100 may alsoinclude the adsorption unit 120 disposed downstream of the hydrotreatingunit 110. Referring to FIG. 4, the system 100 may further include thesecondary hydrocracking unit 190 operable to convert at least a portionof a middle distillate effluent 146 from the hydrocracked effluentseparation system 140 to additional hydrocarbons having boiling pointtemperatures less than or equal to 180° C.

Referring again to FIG. 1, the hydrocarbon feed 102 may include one ormore heavy oils, such as but not limited to crude oil, vacuum residue,tar sands, bitumen, atmospheric residue, vacuum gas oils, other heavyoil streams, or combinations of these. It should be understood that, asused in this disclosure, a “heavy oil” may refer to a raw hydrocarbon,such as crude oil, which has not been previously processed throughdistillation, or may refer to a hydrocarbon which has undergone somedegree of processing prior to being introduced to the system 100 as thehydrocarbon feed 102. The hydrocarbon feed 102 may have a density ofless than or equal to 0.86 grams per milliliter. The hydrocarbon feed102 may have an end boiling point (EBP) of less than 720° C. Thehydrocarbon feed 102 may have a concentration of nitrogen of less thanor equal to 900 parts per million by weight (ppmw).

In one or more embodiments, the hydrocarbon feed 102 may be a crude oil.The crude oil may have an American Petroleum Institute (API) gravity offrom 25 degrees to 50 degrees. For example, the hydrocarbon feed 102 mayinclude an Arab light crude oil. Example properties for an exemplarygrade of Arab light crude oil are listed in Table 1.

TABLE 1 Example of Arab Light Export Feedstock Analysis Units Value TestMethod American Petroleum degree 33.13 ASTM D287 Institute (API) gravityDensity grams per 0.8595 ASTM D287 milliliter (g/mL) Carbon Contentweight 85.29 ASTM D5291 percent (wt. %) Hydrogen Content wt. % 12.68ASTM D5292 Sulfur Content wt. % 1.94 ASTM D5453 Nitrogen Content partsper 849 ASTM D4629 million by weight (ppmw) Asphaltenes wt. % 1.2 ASTMD6560 Micro Carbon Residue wt. % 3.4 ASTM D4530 (MCR) Vanadium (V)Content ppmw 15 IP 501 Nickel (Ni) Content ppmw 12 IP 501 Arsenic (As)Content ppmw 0.04 IP 501 Boiling Point Distribution Initial BoilingPoint Degrees 33 ASTM D7169 (IBP) Celsius (° C.) 5% Boiling Point (BP) °C. 92 ASTM D7169 10% BP ° C. 133 ASTM D7169 20% BP ° C. 192 ASTM D716930% BP ° C. 251 ASTM D7169 40% BP ° C. 310 ASTM D7169 50% BP ° C. 369ASTM D7169 60% BP ° C. 432 ASTM D7169 70% BP ° C. 503 ASTM D7169 80% BP° C. 592 ASTM D7169 90% BP ° C. >720 ASTM D7169 95% BP ° C. >720 ASTMD7169 End Boiling Point (EBP) ° C. >720 ASTM D7169 BP range C5-180° C.wt. % 18.0 ASTM D7169 BP range 180° C.-350° C. wt. % 28.8 ASTM D7169 BPrange 350° C.-540° C. wt. % 27.4 ASTM D7169 BP range >540° C. wt. % 25.8ASTM D7169 Weight percentages in Table 1 are based on the total weightof the crude oil.

When the hydrocarbon feed 102 comprises a crude oil, the crude oil maybe a whole crude or may be a crude oil that has undergone at someprocessing, such as desalting, solids separation, scrubbing. Forexample, the hydrocarbon feed 102 may be a de-salted crude oil that hasbeen subjected to a de-salting process. In some embodiments, thehydrocarbon feed 102 may include a crude oil that has not undergonepretreatment, separation (such as distillation), or other operation thatchanges the hydrocarbon composition of the crude oil prior tointroducing the crude oil to the system 100.

Referring again to FIG. 1, the hydrocarbon feed 102 may be introduceddirectly to the hydrotreating unit 110 or may be combined with hydrogenupstream of the hydrotreating unit 110. The hydrogen may be recycledhydrogen 143 recovered from the system 100, such as from thehydrocracked effluent separation system 140, the steam cracking unit160, or both. The hydrogen may also include supplemental hydrogen 104from an external hydrogen source (not shown). The hydrogen, such asrecycled hydrogen 143, supplemental hydrogen 104, or both, may be passeddirectly to the hydrotreating unit 110 or combined with the hydrocarbonfeed 102 upstream of the hydrotreating unit 110.

The hydrotreating unit 110 may be operable to remove one or a pluralityof impurities, such as metals, sulfur compounds, nitrogen compounds,asphaltenes, or combinations of these, from the hydrocarbon feed 102.Additionally, the hydrotreating unit 110 may be operable to saturate atleast a portion of polyaromatic compounds in the hydrocarbon feed 102.The hydrotreating unit 110 may include at least one hydrotreatingcatalyst, which may be disposed in at least one hydrotreating zonewithin the hydrotreating unit 110. The hydrotreating unit 110 may beoperable to contact the hydrocarbon feed 102 with the at least onehydrotreating catalyst in the presence of hydrogen, where contact withthe hydrotreating catalyst may upgrade the hydrocarbon feed 102 toproduce a hydrotreated effluent 112 having a reduced concentration of atleast one of nitrogen, sulfur, metals, aromatic compounds, orcombinations of these.

The hydrotreating unit 110 may include one or a plurality ofhydrotreating zones. Referring now to FIG. 4, the hydrotreating unit 110may include a plurality of packed bed reaction zones arranged in series,such as one or more of a hydrodemetalization (HDM) reaction zone 114, atransition zone 115, a hydrodesulfurization (HDS) zone 116, ahydrodenitrogenation (HDN) zone 117, a hydrodearomatization (HDA) zone(not shown), or combinations of these reaction zones. Each of theplurality of reaction zones may be disposed in a single reactor or inmultiple reactors in series. Each of the HDM reaction zone 114, thetransition reaction zone 115, the HDS reaction zone 116, the HDNreaction zone 117, and the HDA reaction zone (not shown) may include acatalyst bed comprising a hydrotreating catalyst. The hydrotreating unit110 may include one or a plurality of the HDM reaction zone 114comprising an HDM catalyst, the transition reaction zone 115 comprisinga transition catalyst, the HDS reaction zone 116 comprising an HDScatalyst, an HDN reaction zone 117 comprising an HDN catalyst, the HDAreaction zone comprising an HDA catalyst, or combinations of these. Thereaction zones of the hydrotreating unit 110 may be in any order, andare not necessarily in the order depicted in FIG. 4. In one or moreembodiments, the hydrotreating unit 110 may include the HDM reactionzone 114, the transition reaction zone 115 downstream of the HDMreaction zone 114, and the HDS reaction zone 116 downstream of thetransition reaction zone 115. The hydrotreating unit 110 may include anytype of reactor suitable for contacting the hydrocarbon feed 102 withthe hydrotreating catalysts. Suitable reactors may include, but are notlimited to, fixed bed reactors, moving bed reactors, fluidized bedreactors, plug flow reactors, other types of reactors, or combinationsof reactors. For example, the hydrotreating unit 110 may include one ormore fixed bed reactors, which may be operated in downflow, upflow, orhorizontal flow configurations.

Referring to FIGS. 1 and 4, the hydrotreating catalysts in thehydrotreating unit 110 may include one or more metals selected from themetallic elements in Groups 5, 6, 8, 9, or 10 of the International Unionof Pure and Applied Chemistry (IUPAC) periodic table, such as, but notlimited to, molybdenum, nickel, cobalt, tungsten, or combinations ofthese. The metals of the hydrotreating catalysts may be present as puremetals, metal oxides, metal sulfides, or combinations of these. Themetals, metal oxides, or metal sulfides of the hydrotreating catalystsmay be supported on a support, such as a silica, alumina, or acombination of these. The support material may include, but is notlimited to, gamma-alumina or silica/alumina extrudates, spheres,cylinders, beads, pellets, and combinations thereof. In one or moreembodiments, the hydrotreating catalysts may include nickel andmolybdenum on an alumina support or cobalt and molybdenum on an aluminasupport.

When the hydrotreating catalysts present in the hydrotreating unit 110include an HDM catalyst, the HDM catalyst may include one or more metalsfrom the Groups 5, 6, or 8-10 of the IUPAC periodic table, which may bein the form of metals, metal oxides, or metal sulfides. For example, theHDM catalyst may comprise molybdenum. The HDM catalyst may furthercomprise a support material, and the metal may be disposed on thesupport material. The support material may be a gamma-alumina support,with a surface area of from 100 meters squared per gram (m²/g) to 160m²/g, such as from 100 m²/g to 130 m²/g, or from 130 m²/g to 160 m²/g.The HDM catalyst may include from 0.5 wt. % to 12 wt. % of an oxide orsulfide of molybdenum, such as from 2 wt. % to 10 wt. % or from 3 wt. %to 7 wt. % of an oxide or sulfide of molybdenum based on the totalweight of the HDM catalyst. The HDM catalyst may have a total porevolume of greater than or equal to 0.8 cubic centimeters per gram(cm³/g), greater than or equal to 0.9 cm³/g, or even greater than orequal to 1.0 cm³/g. The HDM catalyst macroporous having an average poresize of greater than or equal to 50 nanometers (nm). The HDM catalystmay include a dopant comprising one or more compounds that includeelements selected from the group consisting of boron, silicon, halogens,phosphorus, and combinations thereof.

When the hydrotreating catalysts present in the hydrotreating unit 110include an HDS catalyst, the HDS catalyst may include one or more metalssupported on a support material. The metals of the HDS catalyst mayinclude one or more metals from Group 6 and one metal from Groups 8-10of the IUPAC periodic table, which may be present as metals, metaloxides, or metal sulfides. The HDS catalyst may include one or moremetals selected from molybdenum, tungsten, nickel, cobalt, orcombinations of these, which may be present as metals, metal oxides, ormetal sulfides. The HDS catalyst may further include a support material,and the metals, metal oxides, or metal sulfides may be disposed on thesupport material. In some embodiments, the HDS catalyst may comprise Moand Ni on an alumina support (sometimes referred to as a “Mo—Ni/Al₂O₃catalyst”). The HDS catalyst may also contain a dopant that is selectedfrom the group consisting of boron, phosphorus, halogens, silicon, andcombinations thereof. The HDS catalyst may include from 10 wt. % to 18wt. % of an oxide or sulfide of molybdenum, such as from 11 wt. % to 17wt. % or from 12 wt. % to 16 wt. % of an oxide or sulfide of molybdenumbased on the total weight of the HDS catalyst. Additionally oralternatively, the HDS catalyst may include from 1 wt. % to 7 wt. % ofan oxide or sulfide of nickel, such as from 2 wt. % to 6 wt. % or from 3wt. % to 5 wt. % of an oxide or sulfide of nickel based on the totalweight of the HDS catalyst. The HDS catalyst may have an average surfacearea of 140 m²/g to 200 m²/g, such as from 140 m²/g to 170 m²/g or from170 m²/g to 200 m²/g. The HDS catalyst can have a total pore volume offrom 0.5 cm³/g to 0.7 cm³/g, such as 0.6 cm³/g. The HDS catalyst maygenerally have a mesoporous structure having pore sizes in the range of2 nm to 50 nm, such as from 12 nm to 50 nm.

When the hydrotreating catalysts present in the hydrotreating unit 110include an HDN catalyst, the HDN catalyst may include a metal oxide orsulfide supported on a support material. The metals of the HDN catalystmay include one or more metals from Groups 5, 6 and 8-10 of the IUPACperiodic table, which may be present as metals, metal oxides, or metalsulfides. In embodiments, the HDN catalyst may contain at least onemetal from IUPAC Group 6, such as molybdenum and at least one metal fromIUPAC Groups 8-10, such as nickel. The HDN catalyst can also include atleast one dopant selected from the group consisting of boron,phosphorus, silicon, halogens, and combinations thereof. In embodiments,cobalt can be used to increase desulfurization of the HDN catalyst. Inembodiments, the HDN catalyst may have a higher metals loading for theactive phase as compared to the HDM catalyst. This increased metalsloading may cause increased catalytic activity. In one or moreembodiments, the HDN catalyst comprises nickel (Ni) and molybdenum (Mo),and has a nickel to molybdenum mole ratio (Ni/(Ni+Mo)) of 0.1 to 0.3(such as from 0.1 to 0.2 or from 0.2 to 0.3). In an embodiment thatincludes cobalt (Co), the mole ratio of (Co+Ni)/Mo may be in the rangeof 0.25 to 0.85 (such as from 0.25 to 0.5 or from 0.5 to 0.85).

The support material may include gamma-alumina, meso-porous alumina,silica, or both, in the form of extrudates, spheres, cylinders andpellets. In embodiments, the HDN catalyst may contain a gamma aluminabased support that has a surface area of 180 m²/g to 240 m²/g (such asfrom 180 m²/g to 210 m²/g, or from 210 m²/g to 240 m²/g). Thisrelatively large surface area for the HDN catalyst may allow for asmaller pore volume (for example, less than 1.0 cm³/g, less than 0.95cm³/g, or even less than 0.9 cm³/g). The HDN catalyst may comprise from10 wt. % to 18 wt. % of an oxide or sulfide of molybdenum, such as from13 wt. % to 17 wt. % or from 14 wt. % to 16 wt. % of an oxide or sulfideof molybdenum, based on the total weight of the HDN catalyst. The HDNcatalyst may comprise from 2 wt. % to 8 wt. % of an oxide or sulfide ofnickel, such as from 3 wt. % to 7 wt. % or from 4 wt. % to 6 wt. % of anoxide or sulfide of nickel, based on the total weight of the HDNcatalyst. The HDN catalyst may include from 74 wt. % to 88 wt. % ofalumina, such as from 76 wt. % to 84 wt. % or from 78 wt. % to 82 wt. %of alumina, based on the total weight of the HDN catalyst.

When the hydrotreating unit 110 includes a transition reaction zone 115,the transition reaction zone 115 may be operable to remove a quantity ofmetal components and a quantity of sulfur components from the HDMreaction effluent stream. The transition catalyst may include analumina-based support in the form of extrudates and at least one metalspecies supported on the alumina-based support. The metal species may bein the form of metals, metal oxides, or metal sulfides. The metalspecies of the transition catalyst may include at least one metal fromGroup 6 and at least one metal from Groups 8-10 of the IUPAC periodictable, which may be in the form of metals, metal oxides, metal sulfides,or combinations of these. Example metals from Group 6 of the IUPACperiodic table include molybdenum and tungsten. Example metals fromIUPAC Group 8-10 include nickel and cobalt. For example, the transitioncatalyst may comprise Mo and Ni on an alumina support (sometimesreferred to as “Mo—Ni/Al₂O₃ catalyst”). The transition catalyst may alsocontain a dopant that is selected from the group consisting of boron,phosphorus, halogens, silicon, and combinations thereof. The transitioncatalyst can have a surface area of 140 m²/g to 200 m²/g (such as from140 m²/g to 170 m²/g or from 170 m²/g to 200 m²/g). The transitioncatalyst can have an intermediate pore volume of from 0.5 cm³/g to 0.7cm³/g (such as 0.6 cm³/g). The transition catalyst may generallycomprise a mesoporous structure having pore sizes in the range of 12 nmto 50 nm. These characteristics provide a balanced activity in HDM andHDS. The transition catalyst may comprise from 10 wt. % to 18 wt. % ofan oxide or sulfide of molybdenum (such as from 11 wt. % to 17 wt. % orfrom 12 wt. % to 16 wt. % of an oxide or sulfide of molybdenum), from 1wt. % to 7 wt. % of an oxide or sulfide of nickel (such as from 2 wt. %to 6 wt. % or from 3 wt. % to 5 wt. % of an oxide or sulfide of nickel),and from 75 wt. % to 89 wt. % of alumina (such as from 77 wt. % to 87wt. % or from 79 wt. % to 85 wt. % of alumina).

When the hydrotreating catalysts present in the hydrotreating unit 110include an HDA catalyst, the HDA catalyst may include one or more metalsfrom Groups 5, 6, 8, 9, or 10 of the IUPAC periodic table, which may bepresent as metals, metal oxides, or metal sulfides. The HDA catalyst mayinclude one or more metals from Groups 5 or 6 of the IUPAC periodictable, and one or more metals from Groups 8, 9, or 10 of the IUPACperiodic table. The HDA catalyst may include one or a plurality ofmolybdenum, tungsten, nickel, cobalt, or combinations of these, whichmay be present as metals, metal oxides, metal sulfides, or combinationsof these. The HDA catalyst may further comprise a support material, suchas zeolite, and the metal may be disposed on the support material. Inone or more embodiments, the HDA catalyst may comprise tungsten andnickel metal catalyst on a zeolite support that is mesoporous (sometimesreferred to as “W—Ni/meso-zeolite catalyst”). In one or moreembodiments, the HDA catalyst may comprise molybdenum and nickel metalcatalyst on a zeolite support that is mesoporous (sometimes referred toas “Mo—Ni/meso-zeolite catalyst”). The zeolite support material may notbe limited to any particular type of zeolite. However, it iscontemplated that zeolites such as Y, Beta, AWLZ-15, LZ-45, Y-82, Y-84,LZ-210, LZ-25, Silicalite, or mordenite framework zeolites may besuitable for use in the presently-described HDA catalyst. The supportmaterial (that is, the mesoporous zeolite) of the HDA catalyst may bemesoporous, having average pore size of from 2 nm to 50 nm.

The HDA catalyst may include from 18 wt. % to 28 wt. % of a sulfide oroxide of tungsten, such as from 20 wt. % to 27 wt. % or from 22 wt. % to26 wt. % of tungsten or a sulfide or oxide of tungsten based on thetotal weight of the HDA catalyst. The HDA catalyst may additionallyinclude, from 2 wt. % to 8 wt. % of an oxide or sulfide of nickel, suchas from 3 wt. % to 7 wt. % or from 4 wt. % to 6 wt. % of an oxide orsulfide of nickel based on the total weight of the HDA catalyst. In oneor more embodiments, the HDA catalyst may comprise from 12 wt. % to 18wt. % of an oxide or sulfide of molybdenum, such as from 13 wt. % to 17wt. % or from 14 wt. % to 16 wt. % of an oxide or sulfide of molybdenumbased on the total weight of the HDA catalyst, and from 2 wt. % to 8 wt.% of an oxide or sulfide of nickel, such as from 3 wt. % to 7 wt. % orfrom 4 wt. % to 6 wt. % of an oxide or sulfide of nickel based on thetotal weight of the HDA catalyst.

The hydrocarbon feed 102 may be contacted with the hydrotreatingcatalysts in the hydrotreating unit 110 at a hydrotreating temperatureand hydrotreating pressure sufficient to upgrade the hydrocarbon feed102 to remove one or a plurality of metals, nitrogen compounds, sulfurcompounds, aromatic compounds, or combinations of these. Thehydrotreating unit 110 may be operated at a hydrotreating temperature offrom 300° C. to 450° C., such as from 350° C. to 420° C. Thehydrotreating unit 110 may be operated at a hydrotreating pressure offrom 50 bar (5,000 kilopascals (kPa)) to 200 bar (20,000 kPa), such asfrom 130 bar (13,000 kPa) to 160 bar (16,000 kPa). The hydroprocessingunit 110 may operate with a liquid hourly volume space velocity (LHSV)of from 0.1 per hour (hr⁻¹) to 1 hr⁻¹, such as from 0.2 hr⁻¹ to 0.7hr⁻¹. The volume ratio of hydrogen to the hydrocarbon feed 102introduced to the hydrotreating unit 110 may be from 800:1 to 1200:1.The hydrogen may be introduced to the hydrotreating unit 110 at theinlet of the hydrotreating unit 110. Referring to FIG. 4, in someembodiments, hydrogen may also be introduced to each of the reactionzones, such as the HDM reaction zone 114, the transition reaction zone115, the HDS reaction zone 116, the HDN reaction zone 117, the HDAreaction zone (not shown), or combinations of these.

Referring again to FIG. 1, the hydrotreated effluent 112 passed out ofthe hydrotreating unit 110 may have a concentration of one or more ofmetals, sulfur-containing hydrocarbons, nitrogen-containinghydrocarbons, and aromatic compounds that is less than a concentrationof these compounds in the hydrocarbon feed 102 by at least 2 percent(%), at least 5%, at least 10%, at least 25%, at least 50%, or even atleast 75%. As previously discussed, contact of the hydrocarbon feed 102with the hydrotreating catalysts, such as the transition catalyst, HDScatalyst, HDN catalyst, or combinations of these, in the presence ofhydrogen in the hydrotreating unit 110 may cause reaction ofsulfur-containing hydrocarbons, nitrogen-containing hydrocarbons, orboth, in the hydrocarbon feed 102 to remove at least a portion of thesulfur and nitrogen from the hydrocarbons of the hydrocarbon feed 102.The sulfur-containing hydrocarbons may be converted to hydrocarbons andsulfur-containing gases, such as hydrogen sulfide (H₂S) for example, andthe nitrogen-containing hydrocarbons may be converted to hydrocarbonsand nitrogen-containing gases, such as ammonia (NH₃). Thesulfur-containing gases and nitrogen-containing gases may be removedfrom the system 100 downstream by the hydrocracked effluent separationsystem 140. The hydrotreated effluent 112 may have concentration ofsulfur-containing hydrocarbons less than a concentration ofsulfur-containing hydrocarbons in the hydrocarbon feed 102. Thehydrotreated effluent 112 may have a concentration of sulfur-containinghydrocarbons of from 0.01 wt. % to 0.10 wt. %, such as from 0.01 wt. %to 0.08 wt. %, from 0.01 wt. % to 0.05 wt. %, from 0.02 wt. % to 0.10wt. %, from 0.02 wt. % to 0.08 wt. %, or from 0.02 wt. % to 0.07 wt. %based on the total weight of the hydrotreated effluent 112. Thehydrotreated effluent 112 may have a concentration ofnitrogen-containing hydrocarbons less than a concentration ofnitrogen-containing hydrocarbons in the hydrocarbon feed 102. Thehydrotreated effluent 112 may have a concentration ofnitrogen-containing hydrocarbons of from 0 parts per million by weight(ppmw) to 500 ppmw, such as from 10 ppmw to 500 ppmw, from 10 ppmw to400 ppmw, from 10 ppmw to 300 ppmw, from 50 ppmw to 500 ppmw, from 50ppmw to 400 ppmw, or from 50 ppmw to 300 ppmw based on the total weightof the hydrotreated effluent 112.

Contact of the hydrocarbon feed 102 with the hydrotreating catalysts,such as the HDM catalyst, transition catalyst, or both, in the presenceof hydrogen in the hydrotreating unit 110 may operate to remove metalsfrom the hydrocarbons. The hydrotreated effluent 112 may have a metalsconcentration that is less than the metals concentration of thehydrocarbon feed 102. The hydroprocessed effluent 103 may have a metalsconcentration of from 0 ppmw to 100 ppmw, such as from 0 ppmw to 75ppmw, from 0 ppmw to 50 ppmw, from 0 ppmw to 25 ppmw, from 0 ppmw to 10ppmw, from 0 ppmw to 5 ppmw, from 0.1 ppmw to 100 ppmw, from 0.1 ppmw to75 ppmw, from 0.1 ppmw to 50 ppmw, from 0.1 ppmw to 25 ppmw, from 0.1ppmw to 10 ppmw, or from 0.1 ppmw to 5 ppmw based on the total weight ofthe hydrotreated effluent 112. The hydrotreated effluent 112 may have anickel concentration that is less than a nickel concentration of thehydrocarbon feed 102, such as a nickel concentration of from 0 ppmw to10 ppmw, from 0.1 ppmw to 5 ppmw, or from 0.1 ppmw to 1 ppmw based onthe total weight of the hydrotreated effluent 112. The hydrotreatedeffluent 112 may have an arsenic content less than an arsenic content ofthe hydrocarbon feed 102, such as from 0 ppmw to 1 ppmw, or from 0.01ppmw to 0.5 ppmw based on the total weight of the hydrotreated effluent112. The hydrotreated effluent 112 may have a vanadium content less thana vanadium content of the hydrocarbon feed 102, such as from 0 ppmw to10 ppmw, such as from 01 ppmw to 5 ppmw, or even from 0.1 ppmw to 1 ppmwbased on the total weight of the hydrotreated effluent 112.

The hydrotreated effluent 112 may have a concentration of aromaticcompounds less than the concentration of aromatic compounds in thehydrocarbon feed 102. The hydrotreated effluent 112 may have aconcentration of aromatic compounds of from 5 wt. % to 40 wt. %, such asfrom 5 wt. % to 30 wt. %, or from 5 wt. % to 20 wt. % based on the totalweight of the hydrotreated effluent 112. The hydrotreated effluent 112may have a concentration of asphaltenes, polyaromatics, and other cokeprecursors that is less than the concentration of asphaltenes,polyaromatics, and other coke precursors in the hydrocarbon feed 102.The hydrotreated effluent 112 may have a concentration of asphaltenes,polyaromatics, and other coke precursors of from 0.01 wt. % to 1 wt. %,such as from 0.01 wt. % to 0.75 wt. %, or from 0.01 wt. % to 0.50 wt. %based on the total weight of the hydrotreated effluent 112.

Still referring to FIG. 1, at least 20 wt. % of the hydrotreatedeffluent 112 may have a boiling point temperature of less than or equalto 225° C. In one or more embodiments, at least 5 wt. %, at least 10 wt.%, at least 20 wt. %, or even at least 30 wt. % of the hydrotreatedeffluent 112 may have a boiling point temperature of less than or equalto 225° C. The hydrotreated effluent 112 may have an initial boilingpoint (IBP) temperature of less than or equal to 100° C., such as lessthan or equal to 90° C., less than or equal to 80° C., less than orequal to 70° C., or even less than or equal to 60° C. The hydrotreatedeffluent 112 may be characterized by a T5 temperature, which is thetemperature below which 5% of the constituents boil. The hydrotreatedeffluent 112 may have a T5 temperature of less than or equal to 150° C.,less than or equal to 130° C., less than or equal to 120° C., less thanor equal to 110° C., or even less than or equal to 100° C. Thehydrotreated effluent 112 may also be characterized by a T95temperature, which is the temperature at which 95% of the constituentsof the hydrotreated effluent 112 boil. In some embodiments, thehydrotreated effluent 112 may have a T95 temperature of greater than orequal to 570° C., greater than or equal to 580° C., greater than orequal to 590° C., greater than or equal to 600° C., or even greater thanor equal to 610° C.

The hydrotreated effluent 112 may have a density less than the densityof the hydrocarbon feed 102. The hydrotreated effluent 112 may have adensity of from 0.80 grams per milliliter (g/mL) to 0.95 g/mL, such asfrom 0.80 g/mL to 0.90 g/mL, from 0.80 g/mL to 0.85 g/mL, from 0.82 g/mLto 0.95 g/mL, from 0.82 g/mL to 0.90 g/mL, from 0.82 g/mL to 0.85 g/mL,from 0.83 g/mL to 0.95 g/mL, 0.83 g/mL to 0.90 g/mL, or from 0.83 g/mLto 0.85 g/mL. The hydrotreated effluent 112 may have an API gravitygreater than the API gravity of the hydrocarbon feed 102 introduced tothe hydrotreating unit 110. The hydrotreated effluent 112 may have anAPI gravity of less than or equal to 50 degrees, or less than or equalto 40 degrees. In some embodiments, the hydrotreated effluent 112 mayhave an API from 25 degrees to 50 degrees, from 30 degrees to 50degrees, from 25 degrees to 45 degrees, or from 255 degrees to 40degrees.

Referring again to FIG. 1, the hydrotreated effluent 112 may be passedto the hydrocracking unit 130, which may be disposed downstream of thehydrotreating unit 110. The hydrocracking unit 130 may be considered theprimary hydrocracking unit of system 100. The hydrocracking unit 130 maybe operable to contact the hydrotreated effluent 112 with ahydrocracking catalyst in the presence of hydrogen in a hydrocrackingzone 132 at reaction conditions sufficient to cause at least a portionof the hydrocarbons in the hydrotreated effluent 112 to undergohydrocracking to produce a hydrocracked effluent 134 having an increasedconcentration of hydrocarbons having boiling point temperatures lessthan or equal to 180° C. compared to the hydrotreated effluent 112. Thehydrocracking unit 130 may include at least a hydrocracking catalyst inthe hydrocracking zone 132. In the hydrocracking unit 130, saturatedpolyaromatic compounds and other larger molecular weight hydrocarbons inthe hydrotreated effluent 112 may be converted to smaller,lesser-boiling hydrocarbons through contact of the hydrotreated effluent112 with the hydrocracking catalyst in the presence of hydrogen. Thehydrocracking unit 130 may be any type of reactor operable to contactthe hydrotreated effluent 112 with the hydrocracking catalyst in thehydrocracking zone 132. Suitable reactors for the hydrocracking unit 130may include, but are not limited to, fixed bed reactors, moving bedreactors, fluidized bed reactors, plug flow reactors, other types ofreactors, or combinations of reactors. For example, the hydrocrackingunit 130 may include one or more fixed bed reactors, which may beoperated in downflow, upflow, or horizontal flow configurations.

Hydrogen may be introduced to the hydrocracking unit 130 with thehydrotreated effluent 112. The hydrogen introduced to the hydrocrackingunit 130 may be recycled hydrogen 143 recovered from the system 100,such as from the hydrocracked effluent separation system 140, the steamcracking unit 160, or both. The hydrogen may also include supplementalhydrogen 104 from an external hydrogen source (not shown). The hydrogen,such as recycled hydrogen 143, supplemental hydrogen 104, or both, maybe passed directly to the hydrocracking unit 130 or combined with thehydrotreated effluent 112 upstream of the hydrocracking unit 130.

The hydrocracking catalyst may be a solid particulate catalyst capableof promoting or increasing the reaction rate of cracking reactions ofhydrocarbons in the presence of hydrogen. Suitable hydrocrackingcatalysts may include, but are not limited to, zeolite catalysts.Examples of zeolite catalysts suitable for use as the hydrocrackingcatalyst may include, but are not limited to, Y-type zeolites, REY-typezeolites, USY-type zeolties, RE-USY-type zeolites, mordenite frameworkinverted (MFI) type zeolites, beta zeolites, or combinations of these.The hydrocracking catalyst may be a hierarchical zeolite containinghydrocracking catalyst, such as but not limited to a hierarchical betazeolite, a hierarchical Y-zeolite, or other hierarchical zeolite.Hierarchical zeolites may refer to zeolites that have an average poresize of from 2 nm to 40 nm, or from 5 nm to 25 nm as determined usingthe Barrett-Joyner-Halinda (BJH) method. Hierarchical zeolites may beprepared by subjecting a microporous beta zeolite or Y-zeolite to adesilication process or by synthesizing the beta zeolite or Y-zeoliteusing a templating agent or pore-directing agent to achieve the desiredhierarchical pore structure.

The hydrocracking catalyst in the hydrocracking unit 130 mayadditionally include one or a plurality of metals supported on thesurfaces of the zeoltites. The hydrocracking catalysts in thehydrocracking unit 130 may include one or a plurality of metals selectedfrom the metallic elements in Groups 6, 7, 8, 9, or 10 of the IUPACperiodic table supported on the zeolite or hierarchical zeolite. Examplemetals for the hydrocracking catalysts of the hydrocracking unit 130 mayinclude but are not limited to molybdenum, cobalt, tungsten, nickel,platinum, palladium, or combinations of these. In one or moreembodiments, the hydrocracking catalyst in the hydrocracking unit 130may include nickel and molybdenum supported on a Y-zeolite or betazeolite support. In one or more embodiments, the hydrocracking catalystin the secondary hydrocracking unit 190 may include nickel and tungstensupported on a Y-zeolite or beta zeolite support. In one or moreembodiments, the hydrocracking catalyst in the hydrocracking unit 130may include platinum and palladium supported on a Y-zeolite or betazeolite support.

The hydrocracking unit 130 may be operated under conditions sufficientto promote or increase the reaction rate of the hydrocracking reactionsto produce the hydrocracked effluent 134 having increased concentrationsof smaller, lesser-boiling hydrocarbons, such as but not limited to C2to C10 paraffins and other hydrocarbons having boiling temperatures lessthan or equal to 180° C. (naphtha). The hydrotreated effluent 112 may becontacted with the hydrocracking catalyst in the hydrocracking unit 130at a hydrocracking temperature and hydrocracking pressure sufficient tocrack at least a portion of the hydrocarbons, such as but not limited tosaturated polyaromatic compounds, in the hydrotreated effluent 112 toproduce smaller, lesser-boiling hydrocarbons having boiling pointtemperatures less than or equal to 180° C. The hydrocracking unit 130may be operated at a hydrocracking temperature of from 300° C. to 450°C., such as from 350° C. to 420° C. The hydrocracking unit 130 may beoperated at a hydrocracking pressure of from 50 bar (5,000 kPa) to 200bar (20,000 kPa), such as from 130 bar (13,000 kPa) to 160 bar (16,000kPa). The hydrocracking unit 130 may operate with a liquid hourly volumespace velocity (LHSV) of from 0.1 per hour (hr⁻¹) to 3 hr⁻¹, such asfrom 0.2 hr⁻¹ to 2 hr⁻¹. The volume ratio of hydrogen to thehydrotreated effluent 112 introduced to the hydrocracking unit 130 maybe from 800:1 to 1200:1. The hydrogen may be introduced to thehydrocracking unit 130 at the inlet of the hydrocracking unit 130.

Referring to FIG. 4, in one or more embodiments, the hydrocracking unit130 may include at least one supplemental hydrotreating zone 131upstream of the hydrocracking zone 132. The supplemental hydrotreatingzone 131 may include a hydrotreating catalyst, such as any of thehydrotreating catalysts previously described in the present disclosure.For example, in one or more embodiments, the hydrotreating catalyst inthe supplemental hydrotreating zone 131 of the hydrocracking unit 130may be a catalyst comprising nickel and molybdenum or cobalt andmolybdenum supported on an alumina catalyst support. The supplementalhydrotreating zone 131 may be disposed in the same reactor as thehydrocracking zone 132 and upstream of the hydrocracking zone 132 or maybe disposed in a separate reactor upstream of the reactor comprising thehydrocracking zone 132.

Hydrocracking catalysts may be at least partially deactivated bydeposition of contaminants, such as coke or asphaltenes, on the surfacesof the hydrocracking catalyst. As previously discussed, hydrotreating ofthe hydrocarbon feed 102 in the hydrotreating unit 110 may deconstructthe compounds that stabilize the solution of asphaltenes and other cokeprecursors in the hydrocarbon feed 102. Upon destruction of thestabilization system, the asphaltenes and other coke precursors mayprecipitate in the hydrotreated effluent 112. When the hydrotreatedeffluent 112 is passed to the hydrocracking unit 130 and contacted withthe hydrocracking catalyst, the precipitated asphaltenes may deposit onthe surfaces of the hydrocracking catalyst. Coke precursors in thehydrotreated effluent 112 may produce coke at the reaction conditions ofthe hydrocracking reaction, and the coke may also deposit on thesurfaces of the hydrocracking catalyst. Thus, the presence ofasphaltenes and other coke precursors in the hydrotreated effluent 112may have a detrimental effect on the service life of the hydrocrackingcatalyst in the hydrocracking unit 130. Even small amounts ofasphaltenes and coke precursors, such as less than 0.5 wt. % in thehydrotreated effluent 112 can cause problems with hydrocracking catalystdeactivation and disrupt smooth steady-state continuous operation of thesystem 100.

Referring to FIG. 1, the system 100 may include an adsorption unit 120operable to remove asphaltenes and other coke precursors from thesystem. The adsorption unit 120 may be disposed downstream of thehydrotreating unit 110. As shown in FIG. 1, the adsorption unit 120 maybe disposed between the hydrotreating unit 110 and the hydrocrackingunit 130. Referring to FIGS. 5 and 6, in one or more embodiments, theadsorption unit 120 may be disposed at other positions within the system100, such as downstream of the hydrocracking unit 130 or between a highpressure separator 150 and a fractionator 154 of the hydrocrackedeffluent separation system 140 downstream of the hydrocracking unit 130.

Referring again to FIG. 1, the adsorption unit 120 may include aplurality of adsorbent beds or adsorption zones, such as a firstadsorption zone 122 and a second adsorption zone 124, which may bearranged in parallel. The adsorption unit 120 is depicted in FIG. 1 ashaving two adsorption zones for ease of illustration and description.However, the adsorption unit 120 may have greater than or equal to twoadsorption zones, such as 2, 3, 4, 5, 6, 7, 8, or more than 8 adsorptionzones. Each adsorbent bed may include adsorbent materials capable ofselectively adsorbing asphaltenes, coke precursors, or both from ahydrocarbon steam, such as the hydrotreated effluent 112, thehydrocracked effluent 134, or other effluent stream of the system 100.Adsorbent materials suitable for the adsorption unit 120 may include,but are not limited to spherical alumina, clay, metal nanoparticles, orcombinations of these. The adsorbent materials may be pelletized. Theadsorbent materials may have a pore volume sufficient to allow largerorganic molecules, such as asphaltenes to adsorb into the pores. Theadsorbent materials may have a total pore volume of greater than orequal to 1.0 milliliters per gram (ml/g), such as greater than or equalto 1.1 ml/g or greater than or equal to 1.5 ml/g. The adsorbentmaterials may have a total pore volume of from 1.0 ml/g to 3.0 ml/g,such as from 1.1 ml/g to 3.0 ml/g, or even from 1.5 ml/g to 3.0 ml/g.

The adsorbent materials may have an uptake of asphaltene of greater thanor equal to 5 grams of asphaltene per gram of adsorbent material, suchas from 5 grams to 20 grams of asphaltene per gram of adsorbentmaterial. The uptake of asphaltene for the adsorbent materials may bedetermined by saturating the adsorbent with asphaltenes. The adsorbentmaterials may be saturated by monitoring an asphaltene concentration inthe effluent exiting the adsorption unit 120. The adsorbent materialsmay be saturated when the asphaltene concentration in the effluent fromthe adsorption unit suddenly increases. Once the adsorbent is saturatedthe adsorption unit may be washed with straight-run diesel for fourhours. The adsorbent may then be unloaded from the adsorption unit 120.100 grams of the saturated adsorbent is weighed out, then washed withtoluene and calcined in a furnace maintained at 700° C. for 8 hours withair flow. After calcination, the adsorbent sample is weighed. The uptakeof asphaltenes can be calculated as the difference between the initial100 gram sample of saturated adsorbent and the final weight of theadsorbent after the asphaltenes have all been removed through washingand calcination.

Referring again to FIG. 1, during operation, the hydrotreated effluent112 may be passed through one or more of the adsorption zones, such asthe first adsorption zone 122, the second adsorption zone 124, or both,in which the hydrotreated effluent 112 is contacted with the adsorbentmaterials. Contact of the hydrotreated effluent 112 with the adsorbentmaterials in the adsorption unit 120 may cause at least a portion of theasphaltenes, coke precursors, or both, to adsorb into the adsorbentmaterials. The adsorption unit 120 may be operated at the operatingconditions of the unit operation immediately upstream of the adsorptionunit 120. When the adsorption unit 120 is positioned immediatelydownstream of the hydrotreating unit 110 and between the hydrotreatingunit 110 and the hydrocracking unit 130, the adsorption unit 120 may beoperated at a temperature and pressure similar to the hydrotreatingtemperature and hydrotreating pressure of the hydrotreating unit 110. Inone or more embodiments, the adsorption unit 120 may be operated at atemperature of from 300° C. to 450° C., such as from 350° C. to 420° C.The adsorption unit 120 may be operated at a pressure of from 50 bar(5,000 kPa) to 200 bar (20,000 kPa), such as from 130 bar (13,000 kPa)to 160 bar (16,000 kPa). The adsorption unit 120 may operate with aliquid hourly volume space velocity (LHSV) of from 5 hr⁻¹ to 10 hr⁻¹.

The hydrotreated effluent 112 passed out of the adsorption unit 120 mayhave a reduced concentration of asphaltenes and other coke precursorscompared to the hydrotreated effluent 112 passed out of thehydrotreating unit 110. The adsorption unit 120 may be operable toremove greater than or equal to 95 percent (%) of the asphaltene fromthe hydrotreated effluent 112 or other effluent passed through theadsorption unit 120. The adsorption unit 120 may be operable removegreater than or equal to 95% or even greater than or equal to 98% of theasphaltene from the hydrotreated effluent 112 or other effluent passedthrough the adsorption unit 120. Removal of the asphaltenes, cokeprecursors, or both from the system 100, such as from the hydrotreatedeffluent 112, may reduce buildup of asphaltenes, coke, or both, on thesurfaces of the hydrocracking catalysts, which may reduce deactivationof the hydrocracking catalyst and improve the service life of thehydrocracking catalysts. Removal of the asphaltenes, coke precursors, orboth, may also reduce buildup of asphaltenes, coke, or both ondownstream equipment, such as downstream separation units or the steamcracking system 160. Reducing the buildup of asphaltenes and coke onhydrocracking catalysts may reduce deactivation of the hydrocrackingcatalysts and increase the conversion of hydrocarbons from thehydrocarbon feed 102 to yield hydrocarbons having boiling pointtemperatures less than or equal to 180° C., which are further processedin the steam cracking system 160 to produce olefins and aromaticcompounds. Thus, removal of the asphaltenes and coke precursors by theadsorption unit 120 may increase the yield of olefins and aromaticcompounds from the system 100.

The adsorption unit 120 may include a plurality of adsorption zones,such as the first adsorption zone 122, the second adsorption zone 124,and any additional adsorption zones, which may be arranged in parallel.The adsorption unit 120 may be operated in a swing mode in which thehydrotreated effluent 112 or other effluent stream is passed through afirst subset of the plurality of adsorbent beds. When the first subsetof adsorbent beds becomes saturated with asphaltenes, coke precursors,or both, the flow of effluent through the adsorption unit 120 may betransitioned to a second subset of adsorbent beds to allow the firstsubset of absorbent beds to be regenerated. For example, in reference toFIG. 1, the hydrotreated effluent 112 may be passed through the firstadsorption zone 122 until the adsorbent materials in the firstadsorption zone 122 become saturated with asphaltenes, coke precursors,or both, and is no longer effective to remove further asphaltenes fromthe hydrotreated effluent 112. Flow of the hydrotreated effluent 112 maybe transitioned to the second adsorption zone 124 while the firstadsorption zone 122 is regenerated.

The adsorbent beds, such as the first adsorption zone 122 and the secondadsorption zone 124, may be regenerated by passing a solvent through theadsorbent bed, the solvent being capable of desorbing and dissolving theasphaltene and coke precursors from the adsorbent materials. Suitablesolvents for regenerating the adsorbent beds may include, but are notlimited to aromatic solvents such as toluene, benzene, or a mixture ofboth. Other solvents capable of dissolving asphaltenes may also be usedto regenerate the adsorbent beds. Other solvents may include alkylalcohols, halogenated hydrocarbons, aromatic compounds or combinationsof these.

Referring again to FIG. 1, the hydrocracked effluent 134 may be passedto the hydrocracked effluent separation system 140. The hydrocrackedeffluent separation system 140 may be operable to separate thehydrocracked effluent 134 to produce the upgraded lesser-boilingeffluent 144, which may be passed to the steam cracking unit 160 as thefeed. The hydrocracked effluent separation system 140 may include one ora plurality of separation units, which, collectively, may be operable toseparate the hydrocracked effluent 134 into at least light gases 142,the upgraded lesser-boiling effluent 144, and the greater-boilingeffluent 148. The hydrocracked effluent separation system 140 may alsobe operable to produce a middle distillate effluent 146.

The light gases 142 may include but are not limited to excess hydrogen,methane, hydrogen sulfide, ammonia, and other light gases. Light gasesmay refer to gases in the hydrotreated effluent 112 that are in gaseousform at ambient temperature and pressure. The light gases 142 mayinclude greater than or equal to 95%, greater than or equal to 97%, oreven greater than or equal to 99% of the light gases from thehydrocracked effluent 134. The light gases 142 may be passed to a gastreatment plant for further processing, such as removal of hydrogensulfide gas and ammonia and separation and purification of hydrogen.Hydrogen recovered from the light gases 142 may be recycled back to thehydrotreating unit 110, the hydrocracking unit 130, or both, as at leasta portion of the recycled hydrogen 143. The recycled hydrogen 143 mayalso include hydrogen recovered from the steam cracking system 160.

The upgraded lesser-boiling effluent 144 may include hydrocarbonconstituents having a boiling point temperature of less than or equal to180° C. The upgraded lesser-boiling effluent 144 may include paraffiniccompounds, such as alkanes having 2 to 10 carbon atoms (C2-C10 alkanes),and other hydrocarbons having boiling point temperatures less than 180°C., such as alkenes and alkynes with boiling temperatures less than 180°C. The upgraded lesser-boiling effluent 144 may include greater than orequal to 95%, greater than or equal to 97%, or even greater than orequal to 98% of the C2-C10 alkanes from the hydrocracked effluent 134.The upgraded lesser-boiling effluent 144 may be passed from thehydrocracked effluent separation system 140 to the steam cracking system160 downstream of the hydrocracked effluent separation system 140.

The middle distillate effluent 146 may include constituents of thehydrocracked effluent 134 having a boiling point temperature of from180° C. to 540° C. The middle distillate effluent 146 may be passed outof the system 100 or recycled back to the hydrotreating unit 110.Referring to FIG. 4, the middle distillate effluent 146 may be passed toa secondary hydrocracking unit 190 for further processing. The secondaryhydrocracking unit 190 will be described in further detail subsequentlyin the present disclosure.

The greater-boiling effluent 148 may include constituents of thehydrocracked effluent 134 having a boiling point temperature greaterthan or equal to 540° C., such as from 540° C. to 720° C. Thegreater-boiling effluent 148 may be passed back to the hydrotreatingunit 110. The system 100 may include a greater-boiling effluent recycle149 which may be operative to pass at least a portion of thegreater-boiling effluent 148 from the hydrocracked effluent separationsystem 140 to the hydrotreating unit 110. The portion of thegreater-boiling effluent 148 passed back in the greater-boiling effluentrecycle 149 may be combined with the hydrocarbon feed 102 upstream ofthe hydrotreating unit 110 or may be passed directly and independentlyto the hydrotreating unit 110. Passing at least a portion of or all ofthe greater-boiling effluent 148 back to the hydrotreating unit 110 mayincrease the yield of olefins and aromatic compounds from the system 100by further converting larger hydrocarbons remaining in thegreater-boiling effluent 148 to smaller paraffinic hydrocarbons moresuitable for processing in the steam cracking system 160.

Referring to FIG. 2, in one or more embodiments, the hydrocrackedeffluent separation system 140 may include at least a high pressureseparator 150 and a fractionator 154. The high pressure separator 150may be operable to separate the hydrocracked effluent 134 into the lightgases 142 and a high pressure separator liquid effluent 152. The lightgases 142 may be passed to a gas treatment plant and the high pressureseparator liquid effluent 152 may be passed on to the fractionator 154.The hydrocracked effluent separation system 140 may additionally includea low pressure separator (not shown) downstream of the high pressureseparator 150 and disposed between the high pressure separator 150 andthe fractionator 154. The low pressure separator may be operable tofurther separate gaseous constituents from the hydrocracked effluent 134to produce the high pressure separator liquid effluent 152. Thefractionator 154 may be operable to separate the high pressure separatorliquid effluent 152 into the upgraded lesser-boiling effluent 144, themiddle distillate effluent 146, and the greater-boiling effluent 148. Inone or more embodiments, the fractionator 154 may include a fractionaldistillation column operable to separate the high pressure separatorliquid effluent 152 into a plurality of different effluent streams basedon differences in boiling point temperatures.

As previously discussed, the upgraded lesser-boiling effluent 144 may bepassed to the steam cracking system 160. Referring to FIG. 3, the steamcracking system 160 may include a steam cracking unit 170 and a steamcracking effluent separation system 180 downstream of the steam crackingunit 170. The steam cracking unit 170 may be operable to contact theupgraded lesser-boiling effluent 144 with steam 161 at a temperaturesufficient to cause at least a portion of the hydrocarbons in theupgraded lesser-boiling effluent 144 to undergo a hydrocracking reactionto produce a steam cracking effluent 176 that includes an increasedconcentration of olefins, aromatic compounds, or both.

The steam cracking system 160 may include a convection zone 172 and apyrolysis zone 174. The upgraded lesser-boiling effluent 144 may passinto the convection zone 172 along with steam 161. In the convectionzone 172, the upgraded lesser-boiling effluent 144 may be pre-heated toa desired temperature, such as from 400° C. to 650° C. The contents ofthe upgraded lesser-boiling effluent 144 present in the convection zone172 may then be passed to the pyrolysis zone 174 where it issteam-cracked to produce the steam cracking effluent 176. The steamcracking effluent 176 may exit the steam cracking system 160 and bepassed through a heat exchanger (not shown) where a process fluid, suchas water or pyrolysis fuel oil, cools the steam cracking effluent 176.The steam cracking effluent 176 may include a mixture of crackedhydrocarbon-based materials which may be separated into one or morepetrochemical products included in one or more system product streams.For example, the steam cracking effluent 176 may include one or more offuel oil, gasoline, mixed butenes, butadiene, propene, ethylene,methane, hydrogen, aromatic compounds, or other hydrocarbons. The steamcracking effluent 176 may additionally include the water from the streamcracking. The pyrolysis zone 174 may operate at a temperature of from700° C. to 900° C. The pyrolysis zone 174 may operate with a residencetime of from 0.05 seconds to 2 seconds. The mass ratio of steam 161 tothe upgraded lesser-boiling effluent 144 may be from about 0.3:1 toabout 2:1.

Referring again to FIG. 3, the steam cracking effluent 176 may be passedto the steam cracking effluent separation system 180. The steam crackingeffluent separation system 180 may be operable to separate the steamcracking effluent 176 into a plurality of effluent streams, such as butnot limited to, a gaseous effluent 162, an olefin effluent 164, anaromatic effluent 166, a pyrolysis oil 168, or combinations of these.The steam cracking effluent separation system 180 may include one or aplurality of separation units, which, collectively, may be operable toseparate the steam cracking effluent 176 into one or more of the gaseouseffluent 162, the olefin effluent 164, the aromatic effluent 166, thepyrolysis oil 168, or combinations of these.

The gaseous effluent 162 may include light gases, such as excesshydrogen, methane, water vapor, or other light gases. As previouslydiscussed, light gases may refer to gases that are in gaseous form atambient temperature and pressure. The gaseous effluent 162 may includegreater than or equal to 95%, greater than or equal to 97%, or evengreater than or equal to 99% of the light gases from the steam crackingeffluent 176. The gaseous effluent 162 may be passed to the gastreatment plant for further processing, such as but not limited toseparation and purification of hydrogen, recovery of methane and otherhydrocarbon gases, or combinations of these. Hydrogen recovered from thegaseous effluent 162 via the gas treatment plant may be recycled back tothe hydrotreating unit 110, the hydrocracking unit 130, or both, as aportion of the recycled hydrogen 143. As previously mentioned, therecycled hydrogen 143 may include hydrogen recovered from both thehydrocracked effluent separation system 140 and the steam crackingsystem 160. In some embodiments, the gaseous effluent 162 and lightgases 142 may be passed to the same gas treatment plant to produce therecycled hydrogen 143.

The olefin effluent 164 may include olefins, such as but not limited to,ethene, propene, butenes (1-butene, cis-2-butene, trans-2-butene,isobutene, or combinations of these), pentene, or other olefins andunsaturated compounds. The olefin effluent 164 may include greater thanor equal to 50%, greater than or equal to 80%, greater than or equal to90%, or even greater than or equal to 95% of the C2-C6 olefins from thesteam cracking effluent 176. The steam cracking effluent 176 may includeother constituents, such as but not limited to saturated hydrocarbonshaving boiling point temperatures similar to the C2-C6 olefins. Theolefin effluent 164 may be passed to one or more processing unitsdownstream of the steam cracking effluent separation system 180 forfurther separation and purification of the olefins produced in the steamcracking system 160.

The aromatic effluent 166 may include one or more aromatic compounds,such as but not limited to benzene, toluene, xylene (o-xylene, m-xylene,p-xylene, or combinations of these), ethylbenzene, other aromaticcompounds, or combinations of aromatic compounds. The aromatic effluent166 may include greater than or equal to 50%, greater than or equal to80%, greater than or equal to 90%, or even greater than or equal to 95%of the C6-C8 aromatic compounds (benzene, toluene, xylenes) from thesteam cracking effluent 176. The aromatic effluent 166 may be passed outof the system 100 to one or a plurality of processing units downstreamof the steam cracking effluent separation system 180 for furtherseparation and purification of the aromatic compounds in the aromaticeffluent 166.

The pyrolysis oil 168 may include constituents of the steam crackingeffluent 176 having a boiling point temperature greater than or equal to540° C., such as from 540° C. to 720° C. Referring again to FIG. 1, thepyrolysis oil 168 may be passed back into the system 100 for furtherconversion of hydrocarbons in the pyrolysis oil 168 to the upgradedlesser-boiling effluent 144. In particular, the pyrolysis oil 168 may bepassed back to the hydrocracked effluent separation system 140, such asback to the fractionator 154 (FIG. 4) of the hydrocracked effluentseparation system 140, in which the pyrolysis oil 168 may be separatedinto various constituents and recycled back through various portions ofthe system 100. At least a portion of the pyrolysis oil 168 may bepassed out of the hydrocracked effluent separation system 140 in thegreater-boiling effluent 148, which may be passed back to thehydrotreating unit 110 through greater-boiling effluent recycle 149. Thegreater-boiling effluent 148 may include at least 50%, at least 80%, atleast 90%, or at least 95% by weight of the pyrolysis oil 168.

Referring now to FIG. 4, as previously discussed, the middle distillateeffluent 146 may be passed from the hydrocracked effluent separationsystem 140, such as from the fractionator 154 of the hydrocrackedeffluent separation system 140, to the secondary hydrocracking unit 190.The secondary hydrocracking unit 190 may be operable to contact themiddle distillate effluent 146 with a hydrocracking catalyst in thepresence of hydrogen in a secondary hydrocracking zone 192 at reactionconditions sufficient to cause at least a portion of the hydrocarbons inthe middle distillate effluent 146 to undergo hydrocracking to produce asecondary hydrocracking effluent 194 having an increased concentrationof paraffins compared to the middle distillate effluent 146. Thesecondary hydrocracking unit 190 may further increase the yield ofolefins, aromatic compounds, or both, from the hydrocarbon feed 102using the system 100 by increasing the conversion of larger hydrocarbonspassed through to the middle distillate effluent 146 to the upgradedlesser-boiling effluent 144, which can be passed to the steam crackingsystem 160. Thus, the secondary hydrocracking unit 190 may increase theconversion of the hydrocarbon feed 102 to the upgraded lesser-boilingeffluent 144, which can result in further increased yield of olefins,aromatic compounds, or both from the system 100.

The secondary hydrocracking unit 190 may include a hydrocrackingcatalyst in the secondary hydrocracking zone 192. In the secondaryhydrocracking unit 190, larger hydrocarbons, such as but not limited tohydrocarbons having greater than 10 carbon atoms, may be converted tosmaller, lesser-boiling hydrocarbons through contact of the middledistillate effluent 146 with the hydrocracking catalyst in the presenceof hydrogen. In particular, the larger hydrocarbons in the middledistillate effluent 146 may be converted to hydrocarbons having boilingtemperatures of less than or equal to 180° C. The secondaryhydrocracking unit 190 may be any type of reactor operable to contactthe middle distillate effluent 146 with the hydrocracking catalyst inthe secondary hydrocracking zone 192. Suitable reactors for thesecondary hydrocracking unit 190 may include, but are not limited to,fixed bed reactors, moving bed reactors, fluidized bed reactors, plugflow reactors, other type of reactor, or combinations of reactors. Forexample, the secondary hydrocracking unit 190 may include one or morefixed bed reactors, which may be operated in downflow, upflow, orhorizontal flow configurations.

Hydrogen may be introduced to the secondary hydrocracking unit 190 alongwith the middle distillate effluent 146. The hydrogen introduced to thesecondary hydrocracking unit 190 may be recycled hydrogen 143 recoveredfrom the system 100, such as from the hydrocracked effluent separationsystem 140, the steam cracking unit 160, or both. The hydrogen may alsoinclude supplemental hydrogen 104 from an external hydrogen source (notshown). The hydrogen, such as recycled hydrogen 143, supplementalhydrogen 104, or both, may be passed directly to the secondaryhydrocracking unit 190 or combined with the middle distillate effluent146 upstream of the secondary hydrocracking unit 190.

Due to removal of the hydrogen sulfide and ammonia gases in thehydrocracked effluent separation system 140, the middle distillateeffluent 146 may be substantially free of these gases. As used in thepresent disclosure, the term “substantially free” of a constituent mayrefer to a composition, stream, catalyst, or reaction zone having lessthan 0.1 wt. % of the constituent. For example, the middle distillateeffluent 146 that is substantially free of hydrogen sulfide, ammonia,other gases, or combinations of gases, may include less than 0.1 wt. %hydrogen sulfide, ammonia, other gases, or combinations of gases. Themiddle distillate effluent 146 being substantially free of hydrogensulfide, ammonia, or both may enable the middle distillate effluent 146to be processed in the secondary hydrocracking unit 190 under lesssevere conditions compared to the hydrocracking unit 130. Due to thedifference in severity of the hydrocracking reaction in the secondaryhydrocracking unit 190 compared to the severity of the hydrocrackingreaction in the hydrocracking unit 130, the hydrocracking reaction inthe secondary hydrocracking unit 190 may favor hydrogenation andring-opening of polyaromatic compounds, which may further improve theoverall yield of olefins, aromatic compounds, or both, from the system100.

The hydrocracking catalyst in the secondary hydrocracking unit 190 maybe any of the hydrocracking catalysts previously described in relationto the hydrocracking unit 130. The hydrocracking catalyst in thesecondary hydrocracking unit 190 may be the same or different than thehydrocracking catalyst disposed in the hydrocracking zone 132 of thehydrocracking unit 130. In some embodiments, the hydrocracking catalystin the secondary hydrocracking unit 190 may be different from thehydrocracking catalyst in the hydrocracking unit 130, which may beenabled by the difference in the severity of operating conditions of thesecondary hydrocracking unit 190 compared to the hydrocracking unit 130.The hydrocracking catalyst in the secondary hydrocracking unit 190 maybe a solid particulate catalyst capable of promoting or increasing thereaction rate of cracking reactions of hydrocarbons in the presence ofhydrogen. Suitable hydrocracking catalysts may include, but are notlimited to, zeolite catalysts. Examples of zeolite catalysts suitablefor use as the hydrocracking catalyst may include, but are not limitedto, Y-type zeolites, REY-type zeolites, USY-type zeolites, RE-USY-typezeolites, mordenite framework inverted (MFI) type zeolites, betazeolites, or combinations of these. In one or more embodiments, thehydrocracking catalyst may include a hierarchical zeolite-containinghydrocracking catalyst, such as but not limited to a hierarchical betazeolite, a hierarchical Y-zeolite, or combinations of these.

The hydrocracking catalyst in the secondary hydrocracking unit 190 mayadditionally include one or a plurality of metals supported on thesurfaces of the zeolites. The hydrocracking catalysts in the secondaryhydrocracking unit 190 may include one or a plurality of metals selectedfrom the metallic elements in Groups 6, 7, 8, 9, or 10 of the IUPACperiodic table supported on the zeolite or hierarchical zeolite. Examplemetals for the hydrocracking catalysts of the secondary hydrocrackingunit 190 may include but are not limited to molybdenum, cobalt,tungsten, nickel, platinum, palladium, or combinations of these. In oneor more embodiments, the hydrocracking catalyst in the secondaryhydrocracking unit 190 may include nickel and molybdenum supported on aY-zeolite or beta zeolite support. In one or more embodiments, thehydrocracking catalyst in the secondary hydrocracking unit 190 mayinclude nickel and tungsten supported on a Y-zeolite or beta zeolitesupport. In one or more embodiments, the hydrocracking catalyst in thesecondary hydrocracking unit 190 may include platinum and palladiumsupported on a Y-zeolite or beta zeolite support.

The secondary hydrocracking unit 190 may be operated under conditionssufficient to promote or increase the reaction rate of the hydrocrackingreactions to produce the secondary hydrocracking effluent 194 havingincreased concentrations of smaller, lesser-boiling hydrocarbons, suchas but not limited to C2 to C10 paraffins and other hydrocarbons havingboiling point temperatures less than 180° C. The middle distillateeffluent 146 may be contacted with the hydrocracking catalyst in thesecondary hydrocracking unit 190 at a hydrocracking temperature andhydrocracking pressure sufficient to crack at least a portion of thehydrocarbons in the middle distillate effluent 146 to produce smaller,lesser-boiling hydrocarbons, such as paraffins and other hydrocarbonshaving boiling point temperatures less than or equal to 180° C. Thehydrocracking reaction in the secondary hydrocracking unit 190 may beconducted under milder conditions compared to the hydrocracking unit 130due to the removal of the hydrogen sulfide and ammonia gases in thehydrocracked effluent separation system 140 upstream of the secondaryhydrocracking unit 190. The secondary hydrocracking unit 190 may beoperated at a hydrocracking temperature of from 300° C. to 400° C., suchas from 300° C. to 475° C. The secondary hydrocracking unit 190 may beoperated at a hydrocracking pressure of from 50 bar (5,000 kPa) to 200bar (20,000 kPa), such as from 130 bar (13,000 kPa) to 160 bar (16,000kPa). The secondary hydrocracking unit 190 may operate with a liquidhourly volume space velocity (LHSV) of from 0.5 per hour (hr⁻¹) to 3.0hr⁻¹, such as from 0.6 hr⁻¹ to 2.0 hr⁻¹. The volume ratio of hydrogen tothe hydrocarbons in the middle distillate effluent 146 introduced to thesecondary hydrocracking unit 190 may be from 1000:1 to 2000:1. Thehydrogen may be introduced to the secondary hydrocracking unit 190 atthe inlet of the secondary hydrocracking unit 190 or may be combinedwith the middle distillate effluent 146 upstream of the secondaryhydrocracking unit 190.

Referring to FIG. 4, contacting the middle distillate effluent 146 withthe hydrocracking catalyst in the secondary hydrocracking zone 192 ofthe secondary hydrocracking unit 190 may cause at least a portion ofhydrocarbons in the middle distillate effluent 146 to undergohydrocracking to produce the secondary hydrocracking effluent 194. Thesecondary hydrocracking effluent 194 may have a greater concentration ofhydrocarbons having a boiling point temperature less than or equal to180° C. compared to the middle distillate effluent 146. The secondaryhydrocracking effluent 194 may be passed to the hydrocracked effluentseparation system 140 for separation of the lesser boiling constituentsinto the upgraded lesser-boiling effluent 144 and other effluentstreams. The secondary hydrocracking effluent 194 may be combined withthe hydrocracked effluent 134 upstream of the hydrocracked effluentseparation system 140 to produce a combined hydrocracked effluent 196.Alternatively or additionally, at least a portion of the secondaryhydrocracking effluent 194 may be passed directly to the hydrocrackedeffluent separation system 140, independent of the hydrocracked effluent134. The hydrocracked effluent separation system 140 may be operable toseparate the secondary hydrocracking effluent 194, the hydrocrackedeffluent 134, or a combination of both, into the light gases 142, theupgraded lesser-boiling effluent 144, the middle distillate effluent146, and the greater-boiling effluent 148.

Referring to FIG. 4, in operation of the system 100, the hydrocarbonfeed 102, the greater-boiling effluent recycle 149, or both, may bepassed to the hydrotreating unit 110 along with hydrogen (recyclehydrogen 143, supplemental hydrogen 104, or both). The hydrotreatingunit 110 may be operable to hydrotreat the hydrocarbon feed 102 toproduce the hydrotreated effluent 112 having reduced concentrations ofone or more of sulfur, nitrogen, metals, polyaromatic compounds, orcombinations of these. The hydrotreated effluent 112 may be passeddirectly from the hydrotreating unit 110 to the adsorption unit 120. Theadsorption unit 120 may be operable to remove at least a portion of theasphaltenes, coke precursors, or both, from the hydrotreated effluent112. In some embodiments, the adsorption unit 120 may be operable toremove at least 95% of the asphaltenes from the hydrotreated effluent112. The hydrotreated effluent 112 may be passed from the adsorptionunit 120 to the hydrocracking unit 130, which may be operable to atleast hydrocrack at least a portion of the hydrocarbons in thehydrotreated effluent 112 to produce the hydrocracked effluent 134,which may have an increased concentration of hydrocarbons having boilingpoint temperatures less than 190° C. compared to the hydrotreatedeffluent 112.

The hydrocracked effluent 134, the secondary hydrocracking effluent 194,or both, may be passed to the hydrocracked effluent separation system140. The hydrocracked effluent separation system 140 may be operable toseparate the hydrocracked effluent 134, secondary hydrocracking effluent194, or both, into at least the light gases 142, the upgradedlesser-boiling effluent 144, the middle distillate effluent 146, and thegreater-boiling effluent 148. The light gases 142 may be passed to a gastreatment plant for recovery of hydrogen, which may be recycled back tothe hydrotreating unit 110, the hydrocracking unit 130, or both. Theupgraded lesser-boiling effluent 144 may be passed directly to the steamcracking system 160, which may be operable to contact the upgradedlesser-boiling effluent 144 with steam at a temperature sufficient tothermally crack at least a portion of the upgraded lesser-boilingeffluent 144 to produce olefins, aromatic compounds, or both. The middledistillate effluent 146 may be passed to the secondary hydrocrackingunit 190, which may be operable to contact the middle distillateeffluent 146 with a second hydrocracking catalyst to further convertlarger hydrocarbons in the middle distillate effluent 146 tohydrocarbons having boiling point temperatures of less than or equal to180° C. The secondary hydrocracking effluent 194 may be combined withthe hydrocracked effluent 134 and passed to the adsorption unit 120 orthe secondary hydrocracking effluent 194 may be separately andindependently passed to the adsorption unit 120. The greater-boilingeffluent 148 may be passed back to the hydrotreating unit 110 forfurther upgrading of hydrocarbons in the greater-boiling effluent 148 tohydrocarbons having boiling point temperatures of less than or equal to180° C.

Referring now to FIG. 5, the adsorption unit 120 may be disposeddownstream of the hydrocracking unit 130 and between the hydrocrackingunit 130 and the hydrocracked effluent separation system 140. An inletof the adsorption unit 120 may be fluidly coupled to an outlet of thehydrocracking unit 130 so that the hydrocracked effluent 134 can bepassed from the hydrocracking unit 130 directly to the adsorption unit120. The adsorption unit 120 may be operable to remove asphaltenes,other coke precursors, or both, from the hydrocracked effluent 134before passing the hydrocracked effluent 134 on to the hydrocrackedeffluent separation system 140. Although not shown in FIG. 5, thesecondary hydrocracking effluent 194 from the secondary hydrocrackingunit 190 may also be passed to the adsorption unit 120 or combined withthe hydrocracked effluent 134 upstream of the adsorption unit 120.

In operation of the system 100 in FIG. 5, the hydrocarbon feed 102, thegreater-boiling effluent recycle 149, or both, may be passed to thehydrotreating unit 110 along with hydrogen (recycle hydrogen 143,supplemental hydrogen 104, or both). The hydrotreating unit 110 may beoperable to hydrotreat the hydrocarbon feed 102 to produce thehydrotreated effluent 112 having reduced concentrations of one or moreof sulfur, nitrogen, metals, polyaromatic compounds, or combinations ofthese. The hydrotreated effluent 112 may be passed directly from thehydrotreating unit 110 to the hydrocracking unit 130, without passingthrough any intervening systems or unit operations that change thecomposition of the hydrotreated effluent 112. The hydrocracking unit 130may be operable to at least hydrocrack at least a portion of thehydrocarbons in the hydrotreated effluent 112 to produce thehydrocracked effluent 134, which may have an increased concentration ofhydrocarbons having boiling point temperatures less than 190° C.compared to the hydrotreated effluent 112. The hydrocracking unit 130may also include a hydrotreating catalyst and may be operable to furtherhydrotreat the hydrotreated effluent 112 before contacting thehydrotreated effluent 112 with the hydrocracking catalyst. Thehydrocracked effluent 134, the secondary hydrocracking effluent 194, orboth, may be passed directly from the hydrocracking unit 130 to theadsorption unit 120. The adsorption unit 120 may be operable to removeat least a portion of the asphaltenes, coke precursors, or both, fromthe hydrocracked effluent 134, the secondary hydrocracking effluent 194,or both. In some embodiments, the adsorption unit 120 may be operable toremove at least 95% of the asphaltenes from the hydrocracked effluent134, the secondary hydrocracking effluent 194, or both.

Following the adsorption unit 120, the hydrocracked effluent 134, thesecondary hydrocracking effluent 194, or both, may be passed to thehydrocracked effluent separation system 140. The hydrocracked effluentseparation system 140 may be operable to separate the hydrocrackedeffluent 134, secondary hydrocracking effluent 194, or both, into atleast the light gases 142, the upgraded lesser-boiling effluent 144, themiddle distillate effluent 146, and the greater-boiling effluent 148.The light gases 142 may be passed to a gas treatment plant for recoveryof hydrogen, which may be recycled back to the hydrotreating unit 110,the hydrocracking unit 130, or both. The upgraded lesser-boilingeffluent 144 may be passed directly to the steam cracking system 160,which may be operable to contact the upgraded lesser-boiling effluent144 with steam at a temperature sufficient to thermally crack at least aportion of the upgraded lesser-boiling effluent 144 to produce olefins,aromatic compounds, or both. The middle distillate effluent 146 may bepassed to the secondary hydrocracking unit 190, which may be operable tocontact the middle distillate effluent 146 with a second hydrocrackingcatalyst to further convert larger hydrocarbons in the middle distillateeffluent 146 to hydrocarbons having boiling point temperatures of lessthan or equal to 180° C. The secondary hydrocracking effluent 194 may becombined with the hydrocracked effluent 134 and passed to the adsorptionunit 120 or the secondary hydrocracking effluent 194 may be separatelyand independently passed to the adsorption unit 120. The greater-boilingeffluent 148 may be passed back to the hydrotreating unit 110 forfurther upgrading of hydrocarbons in the greater-boiling effluent 148 tohydrocarbons having boiling point temperatures of less than or equal to180° C.

Referring now to FIG. 6, the adsorption unit 120 may be disposeddownstream of the hydrocracking unit 130 and between the high pressureseparator 150 and the fractionator 154 of the hydrocracked effluentseparation system 140. An inlet of the adsorption unit 120 may befluidly coupled to an outlet of the high pressure separator 150 so thatthe high pressure separator liquid effluent 152 can be passed from thehigh pressure separator 150 directly to the adsorption unit 120. Theadsorption unit 120 may be operable to remove asphaltenes, other cokeprecursors, or both, from the high pressure separator liquid effluent152 before passing the high pressure separator liquid effluent 152 on tothe fractionator 154.

In operation of the system 100 depicted in FIG. 6, the hydrocarbon feed102, the greater-boiling effluent recycle 149, or both, may be passed tothe hydrotreating unit 110 along with hydrogen (recycle hydrogen 143,supplemental hydrogen 104, or both). The hydrotreating unit 110 may beoperable to hydrotreat the hydrocarbon feed 102 to produce thehydrotreated effluent 112 having reduced concentrations of one or moreof sulfur, nitrogen, metals, polyaromatic compounds, or combinations ofthese. The hydrotreated effluent 112 may be passed directly from thehydrotreating unit 110 to the hydrocracking unit 130, without passingthrough any intervening systems or unit operations that change thecomposition of the hydrotreated effluent 112. The hydrocracking unit 130may be operable to at least hydrocrack at least a portion of thehydrocarbons in the hydrotreated effluent 112 to produce thehydrocracked effluent 134, which may have an increased concentration ofhydrocarbons having boiling point temperatures less than 190° C.compared to the hydrotreated effluent 112. The hydrocracking unit 130may also include a hydrotreating catalyst and may be operable to furtherhydrotreat the hydrotreated effluent 112 before contacting thehydrotreated effluent 112 with the hydrocracking catalyst. Thehydrocracked effluent 134, the secondary hydrocracking effluent 194, orboth, may be passed directly from the hydrocracking unit 130 to the highpressure separator 150. The high pressure separator 150 may be operableto separation the hydrocracked effluent 134, secondary hydrocrackingeffluent 194, or both into the light gases 142 and the high pressureseparator liquid effluent 152. The light gases 142 may be passed to agas treatment plant for recovery of hydrogen, which may be recycled backto the hydrotreating unit 110, the hydrocracking unit 130, or both.

The high pressure separator liquid effluent 152 may be passed directlyto the adsorption unit 120. The adsorption unit 120 may be operable toremove at least a portion of the asphaltenes, coke precursors, or both,from the high pressure separator liquid effluent 152. In one or moreembodiments, the adsorption unit 120 may be operable to remove at least95% of the asphaltenes from the high pressure separator liquid effluent152. Following the adsorption unit 120, the high pressure separatorliquid effluent 152 may be passed to the fractionator 154. Thefractionator 154 may be operable to separate the high pressure separatorliquid effluent 152 into at least the upgraded lesser-boiling effluent144, the middle distillate effluent 146, and the greater-boilingeffluent 148. The upgraded lesser-boiling effluent 144 may be passeddirectly to the steam cracking system 160, which may be operable tocontact the upgraded lesser-boiling effluent 144 with steam at atemperature sufficient to thermally crack at least a portion of theupgraded lesser-boiling effluent 144 to produce olefins, aromaticcompounds, or both. The middle distillate effluent 146 may be passed tothe secondary hydrocracking unit 190, which may be operable to contactthe middle distillate effluent 146 with a second hydrocracking catalystto further convert larger hydrocarbons in the middle distillate effluent146 to hydrocarbons having boiling point temperatures of less than orequal to 180° C. The secondary hydrocracking effluent 194 may becombined with the hydrocracked effluent 134 and passed to the highpressure separator 150 or the secondary hydrocracking effluent 194 maybe separately and independently passed to the high pressure separator150. The greater-boiling effluent 148 may be passed back to thehydrotreating unit 110 for further upgrading of hydrocarbons in thegreater-boiling effluent 148 to hydrocarbons having boiling pointtemperatures of less than or equal to 180° C.

Referring again to FIG. 1, a process for processing the hydrocarbon feed102 may include hydrotreating the hydrocarbon feed 102 to produce thehydrotreated effluent 112, where the hydrotreated effluent 112 mayinclude asphaltenes, coke precursors, or both. The process may furtherinclude hydrocracking at least a portion of the hydrotreated effluent112 to produce a hydrocracked effluent 134. The process may furtherinclude adsorbing at least a portion of the asphaltenes, cokeprecursors, or both, from the hydrotreated effluent 112, thehydrocracked effluent 134, or both, and separating the hydrocrackedeffluent 134 into at least an upgraded lesser-boiling effluent 144 and agreater-boiling effluent 148. The process may further include steamcracking the upgraded lesser-boiling effluent 144 to produce olefins,aromatic compounds, or combinations of these.

Referring again to FIG. 1, a process for converting the hydrocarbon feed102 to olefins, aromatic compounds, or combinations of these, accordingto the present disclosure, may include contacting the hydrocarbon feed102 with at least one hydrotreating catalyst in the presence of hydrogenin at least one hydrotreating zone 114, 115, 116, 117. The hydrocarbonfeed 102 may include a whole crude or desalted whole crude, and thecontacting may remove at least one of metals, sulfur compounds, nitrogencompounds, or combinations of these to produce the hydrotreated effluent112. The process may further include contacting the hydrotreatedeffluent 112 with a hydrocracking catalyst in the presence of hydrogen,where contacting with the hydrocracking catalyst causes at least aportion of hydrocarbons in the hydrotreated effluent 112 to undergohydrocracking reactions to produce the hydrocracked effluent 134. Theprocess may further include contacting at least a portion of thehydrotreated effluent 112, at least a portion of the hydrocrackedeffluent 134, or both with an adsorbent in the adsorption unit 120,where the adsorbent removes at least a portion of asphaltenes, cokeprecursors, or both, from the hydrotreated effluent 112, thehydrocracked effluent 134, or both. The process may further includepassing the hydrocracked effluent 134 to a hydrocracked effluentseparation system 140 operable to separate the hydrocracked effluent 134into at least a upgraded lesser-boiling effluent 144 and a greaterboiling effluent 148 and contacting the upgraded lesser-boiling effluent144 with steam in a steam cracking zone maintained at a steam crackingtemperature, where contacting the upgraded lesser-boiling effluent 144with steam at the steam cracking temperature causes at least a portionof the upgraded lesser-boiling effluent 144 to undergo thermal crackingto produce a steam cracking effluent comprising olefins, aromaticcompounds, or both.

While the present description and examples are provided in the contextof whole crude oil or desalted crude oil as the hydrocarbon feed 102, itshould be understood that systems and processes described in the presentdisclosure may be applicable for the conversion of a wide variety ofheavy oils, including, but not limited to, crude oil, vacuum residue,tar sands, bitumen, atmospheric residue, vacuum gas oils, or other heavyoils.

EXAMPLES

The various embodiments of methods and systems for the processing ofheavy oils will be further clarified by the following examples. Theexamples are illustrative in nature, and should not be understood tolimit the subject matter of the present disclosure.

Example 1: Hydrotreating Process for Hydrotreating Whole Crude Oil

In Example 1, crude oil was hydrotreated in a pilot-plant-sizedhydrotreating unit comprising an HDM catalyst (commercially available asKFR-22 from Albemarle), a transition catalyst (commercially available asKFR-33 from Albemarle), and an HDS catalyst (commercially available asKFR-70 from Albemarle) to reduce the concentration of metals, sulfur,nitrogen, and aromatic compounds in the crude oil. The hydrotreatingunit consisted of a packed column with the HDM catalyst bed on the top,the transition catalyst bed in the middle, and the HDS catalyst bed onthe bottom. The volume ratio of the HDM catalyst to the transitioncatalyst to the HDS catalyst was 15:15:70. For Example 1, the crude oilwas Arab light crude oil, the properties of which were previouslyprovided in Table 1. The hydrotreating unit was operated at atemperature of 390° C. and a pressure of 150 bar. The LHSV was increasedfrom 0.2 h⁻¹ for run 1A, to 0.3 h⁻¹ for run 1B, and to 0.5 h⁻¹ for run1C. The hydrotreated effluents were collected for each of runs 1A, 1B,and 1C from the hydrotreating unit and properties and composition of thehydrotreated effluents were analyzed according to the methods shown inTable 2. These properties included the hydrogen sulfide concentration,the ammonia concentration, the methane concentration (C1), theconcentration of hydrocarbons having from 2 to 4 carbon atoms (C2-C4),the concentration of hydrocarbons having greater than 5 carbons and aboiling point temperature less than or equal to 180° C. (C5-180° C.),the concentration of hydrocarbons having boiling point temperatures from180° C. to 350° C., the concentration of hydrocarbons having boilingpoint temperatures from 350° C. to 540° C., and the concentration ofhydrocarbons having boiling point temperatures greater than 540° C.

TABLE 2 Property Method Density ASTM D287 API ASTM D287 Carbon ContentASTM D5291 Hydrogen Content ASTM D5292 Sulfur Content ASTM D5453Nitrogen Content ASTM D4629 Asphaltenes (Aromatic) Content ASTM D6560Micro Carbon Residue (MCR) ASTM D4530 Metal (V, Ni, As) Content IP 501Hg Content ASTM D7622 SimDis (Boiling Point) ASTM D7169 PIONA D5443Hydrocarbon Structure NOISE

Table 3 provides the operating conditions for the hydrotreating processof Example 1 as well as the composition of the hydrotreating effluentsrecovered from each of runs 1A, 1B, and 1C of Example 1.

TABLE 3 Run 1A Run 1B Run 1C Operating Conditions Temperature (° C.) 390390 390 LHSV (h⁻¹) 0.2 0.3 0.5 Hydrogen consumption (wt. %) 1.92 1.531.27 Hydrogen consumption (scfb) 1038 827 688 Composition (wt. %)Hydrogen Sulfide (H₂S) 2.06 2.05 2.00 Ammonia (NH₃) 0.1 0.08 0.05 C10.35 0.27 0.21 C2-C4 0.88 0.28 0.05 C5-180° C. 19.97 17.84 15.25 180°C.-350° C. 44.16 38.15 38.08 350° C.-540° C. 27.35 29.50 30.43 >540° C.7.18 13.06 15.15 Total Yield C5+ 98.66 98.55 98.90

Example 2: Hydrocracking the Hydrotreated Effluent of Example 1

In Example 2, the hydrotreated effluent from run 1A of Example 1 wassubjected to hydrocracking in a hydrocracking unit. The hydrocrackingunit included a hydrotreating zone comprising an HDS catalyst(commercially available as KFR-70 from Albemarle) and a hydrocrackingzone downstream of the hydrotreating zone and comprising a hydrocrackingcatalyst. The hydrocracking catalyst included molybdenum and nickelsupported on a hierarchical Y-zeolite. The Y-zeolite had a molar ratioof silica (SiO₂) to alumina (Al₂O₃) of 60:1. The hierarchical Y-zeolitewas prepared by treating USY-zeolite with a basic solution (NaOH orammonia) in the presence of a structure directing agent to convert theUSY-zeolite into the hierarchical Y-zeolite. In runs 2A and 2B, theamount of hydrocracking catalyst was 50 wt. % and 30 wt. %,respectively, based on the total weight of HDS and hydrocrackingcatalyst in the hydrocracking unit. The hydrocracking unit was operatedat a temperature of 390° C., a pressure of hydrogen of 150 bar (15,000kPa), and a LHSV of 1.0 h⁻¹. The hydrocracking effluent for each of runs2A and 2B were collected and analyzed for composition and the resultsare reported below in Table 4.

TABLE 4 Run 2A Run 2B LHSV (h−1) 1.0 1.0 Temperature 390 390 Density(g/cc) 0.771 0.799 Sulfur content (ppmw) 230 287 Nitrogen content (ppmw)<5 3.0 Hydrogen consumption (scfb) 1006 2066 Hydrogen sulfide content(wt. %) 2.1 2.08 Ammonia content (wt. %) 0.1 0.09 C1 content (wt. %) 0.40.39 C2 content (wt. %) 0.6 0.48 C3 content (wt. %) 2.1 1.15 nC4 content(wt. %) (normal C4) 3.8 1.34 iC1 content (wt. %) (iso C4) 2.7 1.38 C1-C4total (wt. %) 9.6 4.74 C5-180° C. (wt. %) 53.3 30.03 180° C.-350° C.(wt. %) 31.7 45.60 350° C.-540° C. (wt. %) 3.2 15.18 >540° C. (wt. %)0.0 4.78 Total C5+ hydrocarbons (wt. %) 88.1 95.58

As shown in Table 4, having 50 wt. % hydrocracking catalyst in thehydrocracking unit results in conversion of nearly all of thehydrocarbons having boiling temperatures greater than 350° C. in thehydrotreated effluent into hydrocarbons having boiling temperatures lessthan 350° C. This in turn increases the amount of hydrocarbons havingboiling point temperatures less than or equal to 180° C. in thehydrocracked effluent compared to the hydrotreated effluent.

Example 3: Modeling of System Including Hydrotreating, Hydrocracking,Adsorption, Separation, and Steam Cracking

The composition data from Examples 1 and 2 is used to model the processof FIG. 4 for converting a whole crude oil to olefins and aromaticcompounds through hydrotreating, hydrocracking, adsorption, separationand steam cracking. The process was modeled using Aspen 6 modelingsoftware. The process modeled in Example 3 is depicted in FIG. 4 andincludes the hydrotreating unit 110, which was investigated in Example1, the adsorption unit 120 downstream of the hydrotreating unit 110, thehydrocracking unit 130, which was investigated in Example 2, thehydrocracked effluent separation system 140, the steam cracking system160, and the secondary hydrocracking unit 190. The process modeled inExample 3 includes recycling the greater-boiling effluent 148 back tothe hydrotreating unit 110, hydrocracking the middle distillate effluent146 in the secondary hydrocracking unit 190, and passing the pyrolysisoil from the steam cracking system 160 back to the hydrocracked effluentseparation system 140.

The modeling of the system 100 in FIG. 4 incorporated the conversiondata from the hydrotreating unit evaluated in Example 1 and thehydrocracking unit evaluated in Example 2. Modeling of the system 100 ofFIG. 4 resulted in an upgraded lesser-boiling effluent 144 (feed to thesteam cracking system) having the composition provided in Table 5.

TABLE 5 Constituent Weight Percent (wt. %) C1 0.8 C2-C4 Hydrocarbons12.0 C5-180° C. Hydrocarbons 89.2

The steam cracking system includes a steam cracking unit operated at ahydrocarbon flow rate of 3600 gallons per hour (flowrate of the upgradedlesser-boiling effluent), a water/steam flow rate of 3600 gallons perhour, a temperature of 840° C., and a pressure of 1.8 bar absolute (180kPa absolute). The composition for the steam cracking effluent passedout of the steam cracking unit is provided in Table 6.

Comparative Example 4: Modeling of Process with Hydrotreating,Separating, and Steam Cracking Only

In Comparative Example 4, a process for converting whole crude oil toolefins and aromatic compounds through hydrotreating, separation, andsteam cracking is modeled. The process modeled in Comparative Example 4includes hydrotreating the whole crude according to the hydrotreatingprocess evaluated in Example 1. In Comparative Example 4, thehydrotreated effluent is passed to the separation system in which theupgraded lesser-boiling effluent is separated out and passed on to thesteam cracking system. The process of Comparative Example 4 does notinclude hydrocracking the hydrotreated effluent, adsorption, thesecondary hydrocracking unit 190, or recycling the greater boilingeffluent back to the hydrotreating unit. The process of ComparativeExample 4 also does not include recycling the pyrolysis oil from thesteam cracking system back to the separation system. The process ofComparative Example 4 is described in U.S. Pat. No. 9,255,230.

The hydrotreating unit, separation system, and steam cracking system ofComparative Example 4 are operated under the same operating conditionsas the hydrotreating unit, hydrocracked effluent separation system, andsteam cracking system of Example 3. The steam cracking system operatingconditions and composition of the steam cracking effluent forComparative Example 4 are provided in Table 6.

Comparative Example 5: Modeling of Process with Hydrotreating,Hydrocracking, Separating, and Steam Cracking

In Comparative Example 5, a process for converting whole crude oil toolefins and aromatic compounds through hydrotreating, hydrocracking,separation, and steam cracking is modeled. The process modeled inComparative Example 5 is the same as the process modeled in ComparativeExample 4 with the inclusion of a hydrocracking unit disposed downstreamof the hydrotreating unit and upstream of the separation system. Thehydrocracking process of Example 2 is used as the hydrocracking unit inComparative Example 5. Additionally, the hydrotreating process inComparative Example 5 is the hydrotreating process evaluated inExample 1. The separation unit and steam cracking system are operatedunder the same conditions as in Example 3 and Comparative Example 4. Theprocess of Comparative Example 5 does not include the adsorption unit,the secondary hydrocracking unit 190, recycling the greater boilingeffluent back to the hydrotreating unit, and recycling the pyrolysis oilfrom the steam cracking system back to the separation system. The steamcracking system operating conditions and composition of the steamcracking effluent for Comparative Example 5 are provided in Table 6.

Example 6: Comparison of Example 3 to Comparative Examples 5 and 6

The compositions of the steam cracking effluents from the processesmodeled in Example 3 and Comparative Examples 4 and 5 are provided inthe following Table 6. The hydrotreating catalysts and operatingconditions of the hydrotreating unit, separation systems, and steamcracking systems are the same for Example 3 and Comparative Examples 5and 6. The process modeled in Comparative Example 4 includes thehydrotreating unit, the separation system, and steam cracking system.Comparative Example 5 adds the hydrocracking unit downstream of thehydrotreating unit of the process of Comparative Example 4. Example 3includes the process of FIG. 4, which includes the adsorption unit, thesecondary hydrocracking unit, recycling the greater boiling effluentfrom the separation system back to the hydrotreating unit, and recyclingof the pyrolysis oil from the steam cracking system back to theseparation system. In other words, Example 3 adds the adsorption unit,secondary hydrocracking unit, greater boiling effluent recycle, andpyrolysis recycle to the process modeled in Comparative Example 5.

TABLE 6 Comp. Comp. Example 3 Ex. 4 Ex. 5 Steam Cracking OperatingConditions Hydrocarbon flowrate (gallons/minute) 3600 3600 3600 Waterflowrate (gallons/minute) 3600 3600 3600 Temperature (° C.) 840 840 840Pressure (kPa absolute) 180 180 180 Olefin Yields (wt. %) Hydrogen 0.90.6 0.7 Ethylene (C₂H₄) 30.4 20.7 23.2 Acetylene (C₂H₂) 1.0 0.4 0.4Propene (C₃H₆) 16.6 10.3 11.6 Propadiene (C₃H₄) 0.9 0.3 0.3Methylacetylene (C₃H₄) 0.8 0.3 0.4 1-Butene 2.2 1.1 1.1 trans-2-Butene1.0 0.3 0.4 cis-2-Butene 0.5 0.3 0.3 Isobutene 2.2 1.2 1.4 1,3-Butadiene6.5 3.7 4.6 C5+ Yield Benzene 8.8 4.7 5.7 Toluene 8 3.8 5 Xylenes(para-, meta-, ortho-) 5.5 1.2 2.5 Total BTX (benzene, toluene, xylenes)22.3 9.7 13.2 Total C5-C10 11.5 8.4 8.5 C10+ 3.1 18.1 19.1 Rate of CokeFormation in Reactor 0.4 0.6 0.4 (grams coke/hr)

As shown by the results in Table 6, the system of the present disclosuremodeled in Example 3 produced greater yields of olefins, such asethylene, propene, and butene, and greater yields of aromatic compounds,such as benzene, toluene, and xylenes, compared to the systems ofComparative Examples 4 and 5. Additionally, the system of Example 3produced one sixth of the C10+ compounds in the steam cracker effluentcompared to the amount of C10+ constituents in the steam crackingeffluents produced in the systems of Comparative Examples 4 and 5. Thus,the data presented in Table 6 demonstrate that the system of Example 3upgrades a greater proportion of hydrocarbons from the crude oil intoolefins and aromatic compounds compared to existing processes forupgrading crude oil and other heavy oils.

A first aspect of the present disclosure may include a process forupgrading a hydrocarbon feed. The process may include hydrotreating ahydrocarbon feed to produce a hydrotreated effluent, where thehydrotreated effluent may comprise asphaltenes, coke precursors, orboth. The process may further include hydrocracking the at least aportion of the hydrotreated effluent to produce a hydrocracked effluentand adsorbing at least a portion of the asphaltenes, coke precursors, orboth, from the hydrotreated effluent, the hydrocracked effluent, orboth. The process may further include separating the hydrocrackedeffluent into at least an upgraded lesser-boiling effluent and agreater-boiling effluent and steam cracking the upgraded lesser-boilingeffluent to produce olefins, aromatic compounds, or combinations ofthese.

A second aspect of the present disclosure may include the first aspect,further comprising combining the greater-boiling effluent with thehydrocarbon feed before hydrotreating the hydrocarbon feed.

A third aspect of the present disclosure may include any one of thefirst or second aspects, where adsorbing the at least a portion of theasphaltene, coke precursors, or both comprises contacting thehydrotreated effluent with an adsorbent, where contact with theadsorbent causes at least a portion of the asphaltene, coke precursors,or both to adsorb onto the adsorbent.

A fourth aspect of the present disclosure may include any one of thefirst through third aspects, comprising adsorbing at least 95 percent byweight of the asphaltenes, coke precursors, or both, from thehydrotreated effluent.

A fifth aspect of the present disclosure may include any one of thefirst through fourth aspects, in which adsorbing the at least a portionof the asphaltenes, coke precursors, or both may reduce deactivation ofthe hydrocracking catalyst during hydrocracking of the hydrotreatedeffluent.

A sixth aspect of the present disclosure may include any one of thefirst through fifth aspects, comprising separating the hydrocrackedeffluent into the upgraded lesser-boiling effluent, a middle distillateeffluent, and the greater-boiling effluent and contacting the middledistillate effluent with a secondary hydrocracking catalyst in thepresence of hydrogen to produce a secondary hydrocracked effluent.

A seventh aspect of the present disclosure may include the sixth aspect,further comprising combining the secondary hydrocracked effluent withthe hydrocracked effluent to produce a combined hydrocracked effluentand separating the combined hydrocracked effluent into the upgradedlesser-boiling effluent, the middle distillate effluent, and thegreater-boiling effluent.

An eighth aspect of the present disclosure may include any one of thefirst through seventh aspects, further comprising passing thegreater-boiling effluent into contact with the hydrocarbon feed andhydrotreating the greater-boiling effluent and the hydrocarbon feed.

A ninth aspect of the present disclosure may include any one of thefirst through eighth aspects, where hydrotreating may comprisecontacting the hydrocarbon feed with at least one hydrotreating catalystin the presence of hydrogen in at least one hydrotreating zone.

A tenth aspect of the present disclosure may include any one of thefirst through ninth aspects, where hydrotreating may remove at least oneor more metals, nitrogen compounds, sulfur compounds, or combinations ofthese.

An eleventh aspect of the present disclosure may include any one of thefirst through tenth aspects, where hydrocracking may comprise contactingthe portion of the hydrotreated effluent with a hydrocracking catalystin the presence of hydrogen to produce the hydrocracked effluent. Thehydrocracked effluent may have a greater concentration of hydrocarbonshaving boiling point temperatures less than or equal to 180° C. comparedto the hydrotreated effluent.

A twelfth aspect of the present disclosure may include any one of thefirst through eleventh aspects, comprising separating a steam crackingeffluent into at least one product effluent and a pyrolysis oileffluent, combining the pyrolysis oil effluent with at least a portionof the hydrocracked effluent, and separating the combined pyrolysis oileffluent and hydrocracked effluent into at least the upgradedlesser-boiling effluent and the greater-boiling effluent.

A thirteenth aspect of the present disclosure may include any one of thefirst through twelfth aspects, where the hydrocarbon feed comprises awhole crude or a de-salted whole crude.

A fourteenth aspect of the present disclosure may be directed to aprocess for upgrading a hydrocarbon feed. The process may includecontacting the hydrocarbon feed with at least one hydrotreating catalystin the presence of hydrogen in at least one hydrotreating zone. Thehydrocarbon feed may comprise whole crude or desalted whole crude andthe contacting may remove at least one of metals, sulfur compounds,nitrogen compounds, or combinations of these to produce a hydrotreatedeffluent. The process may further include contacting the hydrotreatedeffluent with a hydrocracking catalyst in the presence of hydrogen,where contacting with the hydrocracking catalyst may cause at least aportion of hydrocarbons in the hydrotreated effluent to undergohydrocracking reactions to produce a hydrocracked effluent. The processmay further include contacting at least a portion of the hydrotreatedeffluent or at least a portion of the hydrocracked effluent with anadsorbent in an adsorption unit. The adsorbent may remove at least aportion of asphaltenes, coke precursors, or both, from the portion ofthe hydrotreated effluent or the portion of the hydrocracked effluent.The process may further include passing the hydrocracked effluent to ahydrocracked effluent separation system operable to separate thehydrocracked effluent into at least an upgraded lesser-boiling effluentand a greater boiling effluent and contacting the upgradedlesser-boiling effluent with steam in a steam cracking zone maintainedat a steam cracking temperature. Contacting the upgraded lesser-boilingeffluent with steam at the steam cracking temperature may cause at leasta portion of the upgraded lesser-boiling effluent to undergo thermalcracking to produce a steam cracking effluent comprising olefins,aromatic compounds, or both.

A fifteenth aspect of the present disclosure may include the fourteenthaspect, further comprising passing the greater-boiling effluent to theat least one hydrotreating zone.

A sixteenth aspect of the present disclosure may include either one ofthe fourteenth or fifteenth aspects, in which contacting thehydrotreated effluent or the hydrocracked effluent with the adsorbent inthe adsorption unit may remove at least 95 percent by weight of theasphaltenes, coke precursors, or both, from the hydrotreated effluent orthe hydrocracked effluent.

A seventeenth aspect of the present disclosure may include any one ofthe fourteenth through sixteenth aspects, where contacting thehydrotreated effluent or the hydrocracked effluent with the adsorbent inthe adsorption unit may reduce deactivation of the hydrocrackingcatalyst during hydrocracking of the hydrotreated effluent.

An eighteenth aspect of the present disclosure may include any one ofthe fourteenth through seventeenth aspects, where the hydrocrackedeffluent may have a greater concentration of hydrocarbons having boilingpoint temperatures less than or equal to 180° C. compared to thehydrotreated effluent.

A nineteenth aspect of the present disclosure may include any one of thefourteenth through eighteenth aspects, in which the hydrocrackedeffluent separation system may be operable to separate the hydrocrackedeffluent into at least the upgraded lesser-boiling effluent, a middledistillate effluent, and the greater-boiling effluent, and the processmay further comprise contacting the middle distillate effluent with asecondary hydrocracking catalyst in the presence of hydrogen to producea secondary hydrocracked effluent.

A twentieth aspect of the present disclosure may include the nineteenthaspect, in which the secondary hydrocracked effluent may have a greaterconcentration of hydrocarbons having a boiling point temperature lessthan or equal to 180° C. compared to the middle distillate effluent.

A twenty-first aspect of the present disclosure may include either oneof the nineteenth or twentieth aspects, in which the secondaryhydrocracking catalyst may comprise at least one metal catalystsupported on Y-zeolite, beta-zeolite, or both.

A twenty-second aspect of the present disclosure may include thetwenty-first aspect, in which the metal catalyst may comprise at leastone metal selected from the group consisting of cobalt, molybdenum,nickel, platinum, palladium, and combinations of these.

A twenty-third aspect of the present disclosure may include either oneof the twenty-first or twenty-second aspects, in which the Y-zeolite,beta-zeolite, or both comprise hierarchical Y-zeolite, hierarchicalbeta-zeolite, or both, respectively.

A twenty-fourth aspect of the present disclosure may include any one ofthe nineteenth through twenty-third aspects, further comprising passingthe secondary hydrocracked effluent to the hydrocracked effluentseparation system.

A twenty-fifth aspect of the present disclosure may include any one ofthe nineteenth through twenty-fourth aspects, further comprisingcombining the secondary hydrocracked effluent with the hydrocrackedeffluent to produce a combined hydrocracked effluent and passing thecombined hydrocracked effluent to the hydrocracked effluent separationsystem.

A twenty-sixth aspect of the present disclosure may include any one ofthe fourteenth through twenty-fifth aspects, in which the steam crackereffluent may include at least one of ethylene, propylene, butene, orcombinations of these.

A twenty-seventh aspect of the present disclosure may include any one ofthe fourteenth through twenty-sixth aspects, in which the steam crackereffluent may include aromatic compounds that include at least one ofbenzene, toluene, xylenes, or combinations of these.

A twenty-eighth aspect of the present disclosure may include any one ofthe fourteenth through twenty-seventh aspects, comprising separating asteam cracking effluent into at least one product effluent and apyrolysis oil effluent and passing the pyrolysis oil effluent back tothe hydrocracked effluent separation system.

A twenty-ninth aspect of the present disclosure may include thetwenty-eighth aspect in which the at least one product effluent maycomprise at least an olefin effluent comprising one or more olefins andan aromatic effluent comprising one or more aromatic compounds.

A thirtieth aspect of the present disclosure may include any one of thefirst through twenty-ninth aspects, where the adsorbent may include atleast one of spherical alumina, clay, metal nanoparticles, orcombinations of these.

A thirty-first aspect of the present disclosure may include any one ofthe first through thirtieth aspects, further comprising regenerating theadsorbent by contacting the adsorbent with a solvent capable ofdissolving asphaltenes, coke precursors, or both.

A thirty-second aspect of the present disclosure may include any one ofthe first through thirty-first aspects, where the hydrocracking catalystcomprises one or a plurality of metals supported on Y-zeolite, betazeolite, or both.

A thirty-third aspect of the present disclosure may include thethirty-second aspect, in which the metals of the hydrocracking catalystmay include at least one of cobalt, molybdenum, nickel, platinum,palladium, or combinations of these.

A thirty-fourth aspect of the present disclosure may include thethirty-second aspect, in which the metals of the hydrocracking catalystmay include at least one metal selected from the group consisting ofcobalt, molybdenum, nickel, platinum, palladium, or combinations ofthese.

A thirty-fifth aspect of the present disclosure may include any one ofthe thirty-second through thirty-fourth aspects, in which the Y-zeolite,beta-zeolite, or both, comprise hierarchical Y-zeolite, hierarchicalbeta-zeolite, or both, respectively

A thirty-sixth aspect of the present disclosure may include a system forprocessing crude oil. The system may include a hydrotreating unitcomprising at least one hydrotreating catalyst. The hydrotreating unitmay be operable to contact the crude oil with the at least onehydrotreating catalyst. Contact with the hydrotreating catalyst mayupgrade the crude oil to a hydrotreated effluent having a reducedconcentration of at least one of nitrogen, sulfur, metals, aromaticcompounds, or combinations of these. The system may further include ahydrocracking unit disposed downstream of the hydrotreating unit andcomprising a hydrocracking catalyst. The hydrocracking unit may beoperable to contact at least a portion of the hydrotreated effluent withthe hydrocracking catalyst at conditions sufficient to convert at leasta portion of the hydrotreated effluent to produce a hydrocrackedeffluent comprising hydrocarbons having a boiling point temperature lessthan or equal to 180° C. The system may further include an adsorptionunit downstream of the hydrotreating unit or the hydrocracking unit. Theadsorption unit may be operable to contact the hydrotreated effluent orthe hydrocracked effluent with an adsorbent capable of adsorbingasphaltenes, coke precursors, or both from the hydrotreated effluent orthe hydrocracked effluent. The system may further include a hydrocrackedeffluent separation system downstream of the hydrocracking unit. Thehydrocracked effluent separation system may be operable to separate atleast a portion of the hydrocracked effluent into at least an upgradedlesser-boiling effluent and a greater-boiling effluent. The system mayfurther include a steam cracking system downstream of the hydrocrackedeffluent separation system. The steam cracking system may be operable toconvert at least a portion of the upgraded lesser-boiling effluent toproduce olefins, aromatic compounds, or both.

A thirty-seventh aspect of the present disclosure may include thethirty-sixth aspect, further comprising a greater-boiling effluentrecycle fluidly coupled to the hydrocracked effluent separation systemand to the hydrotreating unit. The greater-boiling effluent recycle maybe operable to transfer the greater-boiling effluent from thehydrocracked effluent separation system back to the hydrotreating unit.

A thirty-eighth aspect of the present disclosure may include either oneof the thirty-sixth or thirty-seventh aspects, in which the hydrocrackedeffluent separation system may be operable to separate the hydrocrackedeffluent into at least the upgraded lesser-boiling effluent, thegreater-boiling effluent, and a middle distillate effluent, and thesystem further may comprise a secondary hydrocracking unit that may beoperable to contact the middle distillate effluent with a secondaryhydrocracking catalyst to produce a secondary hydrocracked effluent.

A thirty-ninth aspect of the present disclosure may include any one ofthe thirty-sixth through thirty-eighth aspects, further comprising apyrolysis oil recycle fluidly coupled to the steam cracking system andthe hydrocracked effluent separation system. The pyrolysis oil recyclemay be operable to transfer a pyrolysis oil effluent from the steamcracking system back to the hydrocracked effluent separation system.

A fortieth aspect of the present disclosure may include any one of thethirty-sixth through thirty-ninth aspects, in which the adsorption unitmay be disposed between the hydrotreating unit and the hydrocrackingunit.

A forty-first aspect of the present disclosure may include any one ofthe thirty-sixth through fortieth aspects, in which the adsorption unitmay be disposed downstream of the hydrocracking unit.

A forty-second aspect of the present disclosure may include any one ofthe thirty-sixth through forty-first aspects, in which the adsorptionunit may be disposed between the hydrocracking unit and the hydrocrackedeffluent separation system.

A forty-third aspect of the present disclosure may include any one ofthe thirty-sixth through forty-second aspects, in which the hydrocrackedeffluent separation system may comprise at least a high-pressureseparator and a fractionator downstream of the high pressure separator.

A forty-fourth aspect of the present disclosure may include theforty-third aspect, in which the adsorption unit may be disposed betweenthe high-pressure separator and the fractionator.

A forty-fifth aspect of the present disclosure may include any one ofthe thirty-sixth through forty-fourth aspects, in which the adsorptionunit may comprise a plurality of adsorption zones in parallel.

A forty-sixth aspect of the present disclosure may include any one ofthe thirty-sixth through forty-fifth aspects, in which the adsorbent maycomprise spherical alumina, clay, metal nanoparticles, or combinationsof these.

A forty-seventh aspect of the present disclosure may include any one ofthe thirty-sixth through forty-sixth aspects, in which the hydrotreatingunit comprises a plurality of hydrotreating zones in series.

A forty-eighth aspect of the present disclosure may include any one ofthe thirty-sixth through forty-seventh aspects, in which thehydrotreating catalyst may comprise at least one of a desulfurizationcatalyst, a transition catalyst, a denitrogenation catalyst, ademetalization catalyst, a de-aromatization catalyst, or combinations ofthese.

A forty-ninth aspect of the present disclosure may include any one ofthe thirty-sixth through forty-eighth aspects, in which thehydrotreating unit may comprise a desulfurization reaction zonecomprising a desulfurization catalyst, a transition reaction zonecomprising a transition catalyst, and a demetalization reaction zonecomprising a demetalization catalyst.

A fiftieth aspect of the present disclosure may include any one of thethirty-sixth through forty-ninth aspects, in which the hydrocrackingcatalyst comprises a metal supported on a zeolite.

A fifty-first aspect of the present disclosure may include the fiftiethaspect, in which the metal of the hydrocracking catalyst may comprise atleast one of cobalt, molybdenum, nickel, platinum, palladium, orcombinations of these, and the zeolite comprises hierarchical Y-zeolite,hierarchical beta-zeolite, or both.

A fifty-second aspect of the present disclosure may include any one ofthe thirty-sixth through fifty-first aspects, in which the hydrocrackingunit may comprise a supplemental hydrotreating zone upstream of thehydrocracking zone and comprising a hydrotreating catalyst.

A fifty-third aspect of the present disclosure may include any one ofthe thirty-sixth through fifty-second aspects, in which the steamcracking system may comprise a steam cracking unit and a steam crackingeffluent separation system.

A fifty-fourth aspect of the present disclosure may include thefifty-third aspect, in which the steam cracking unit may be operable tocontact the upgraded lesser-boiling effluent with steam at a steamcracking temperature of from 700 degrees Celsius to 900 degrees Celsiusproduce a steam cracking effluent.

A fifty-fifth aspect of the present disclosure may include either one ofthe fifty-third or fifty-fourth aspects, in which the steam crackingeffluent separation system may be operable to separate the steamcracking effluent into at least one product effluent and a pyrolysis oileffluent.

A fifty-sixth aspect of the present disclosure may include thefifty-fifth aspect, in which the at least one product effluent maycomprise at least one olefin effluent, at least one aromatic compoundeffluent, or both.

It is noted that one or more of the following claims utilize the term“where” as a transitional phrase. For the purposes of defining thepresent technology, it is noted that this term is introduced in theclaims as an open-ended transitional phrase that is used to introduce arecitation of a series of characteristics of the structure and should beinterpreted in like manner as the more commonly used open-ended preambleterm “comprising.”

It should be understood that any two quantitative values assigned to aproperty may constitute a range of that property, and all combinationsof ranges formed from all stated quantitative values of a given propertyare contemplated in this disclosure.

Having described the subject matter of the present disclosure in detailand by reference to specific embodiments, it is noted that the variousdetails described in this disclosure should not be taken to imply thatthese details relate to elements that are essential components of thevarious embodiments described in this disclosure, even in cases where aparticular element is illustrated in each of the drawings that accompanythe present description. Rather, the claims appended hereto should betaken as the sole representation of the breadth of the presentdisclosure and the corresponding scope of the various embodimentsdescribed in this disclosure. Further, it will be apparent thatmodifications and variations are possible without departing from thescope of the appended claims.

What is claimed is:
 1. A system for processing crude oil, the systemcomprising: a hydrotreating unit comprising at least one hydrotreatingcatalyst, the hydrotreating unit operable to contact the crude oil withhydrogen in the presence of at least one hydrotreating catalyst, wherecontact with the hydrogen in the presence of the hydrotreating catalystupgrades the crude oil to a hydrotreated effluent having a reducedconcentration of at least one of nitrogen, sulfur, metals, aromaticcompounds, or combinations of these; a hydrocracking unit disposeddownstream of the hydrotreating unit and comprising a hydrocrackingcatalyst, the hydrocracking unit operable to contact at least a portionof the hydrotreated effluent with hydrogen in the presence of thehydrocracking catalyst at conditions sufficient to convert at least aportion of the hydrotreated effluent to produce a hydrocracked effluent;an adsorption unit downstream of the hydrotreating unit or downstream ofthe hydrocracking unit, where the adsorption unit comprises an adsorbentand is operable to contact the hydrotreated effluent or the hydrocrackedeffluent with the adsorbent capable of adsorbing asphaltenes, cokeprecursors, or both from the hydrotreated effluent or the hydrocrackedeffluent; a hydrocracked effluent separation system downstream of thehydrocracking unit, the hydrocracked effluent separation system operableto separate at least a portion of the hydrocracked effluent into atleast an upgraded lesser-boiling effluent and a greater-boilingeffluent; and a steam cracking system downstream of the hydrocrackedeffluent separation system, where the steam cracking system is operableto contact the upgraded lesser-boiling effluent with steam at atemperature sufficient to cause hydrocarbons in the upgradedlesser-boiling effluent to react to produce olefins, aromatic compounds,or both.
 2. The system of claim 1, further comprising a greater-boilingeffluent recycle fluidly coupled to the hydrocracked effluent separationsystem and to the hydrotreating unit, the greater-boiling effluentrecycle operable to transfer the greater-boiling effluent from thehydrocracked effluent separation system back to the hydrotreating unit.3. The system of claim 1, where the hydrocracked effluent separationsystem is operable to separate the hydrocracked effluent into at leastthe upgraded lesser-boiling effluent, the greater-boiling effluent, anda middle distillate effluent, and the system further comprises asecondary hydrocracking unit fluidly coupled to the hydrocrackedeffluent separation system to receive the middle distillate effluentfrom the hydrocracked effluent separation system.
 4. The system of claim3, where the secondary hydrocracking unit comprises a secondaryhydrocracking catalyst and is operable to contact the middle distillateeffluent with the secondary hydrocracking catalyst to produce asecondary hydrocracked effluent.
 5. The system of claim 1, furthercomprising a pyrolysis oil recycle fluidly coupled to the steam crackingsystem and the hydrocracked effluent separation system, the pyrolysisoil recycle operable to transfer a pyrolysis oil effluent from the steamcracking system back to the hydrocracked effluent separation system. 6.The system of claim 1, where the adsorption unit is disposed between thehydrotreating unit and the hydrocracking unit.
 7. The system of claim 1,where the hydrotreating catalyst comprises at least one of adesulfurization catalyst, a transition catalyst, a denitrogenationcatalyst, a demetalization catalyst, a de-aromatization catalyst, orcombinations of these.
 8. The system of claim 1, where the hydrotreatingunit comprises: a desulfurization reaction zone comprising adesulfurization catalyst; a transition reaction zone comprising atransition catalyst; and a demetalization reaction zone comprising atdemetalization catalyst.
 9. The system of claim 1, where the adsorptionunit is disposed downstream of the hydrocracking unit.
 10. The system ofclaim 9, where an inlet of the adsorption unit is fluidly coupled to anoutlet of the hydrocracking unit.
 11. The system of claim 9, where thehydrocracked effluent separation system comprises a high pressureseparator and a fractionator downstream of the high pressure separator.12. The system of claim 11, where the adsorption unit is disposedbetween the high pressure separator and the fractionator and an inlet ofthe adsorption unit is in fluid communication with an outlet of the highpressure separator.
 13. A process for upgrading a hydrocarbon feed withthe system of claim 1, the process comprising: introducing thehydrocarbon feed to the hydrotreating unit of the system of claim 1,where the adsorption unit is disposed downstream of the hydrocrackingunit; hydrotreating the hydrocarbon feed in the hydrotreating unit toproduce a hydrotreated effluent; hydrocracking the hydrotreated effluentin the hydrocracking unit to produce a hydrocracked effluent, where thehydrocracked effluent comprises asphaltenes, coke precursors, or both;adsorbing at least a portion of the asphaltenes, coke precursors, orboth, from the hydrocracked effluent; separating the hydrocrackedeffluent into at least an upgraded lesser-boiling effluent and agreater-boiling effluent; and contacting the upgraded lesser-boilingeffluent with steam at a temperature sufficient to cause hydrocarbons inthe upgraded lesser-boiling effluent to react to produce olefins,aromatic compounds, or combinations of these.
 14. The process of claim13, further comprising: separating the hydrocracked effluent into theupgraded lesser-boiling effluent, a middle distillate effluent, and thegreater-boiling effluent; and contacting the middle distillate effluentwith a secondary hydrocracking catalyst in the presence of hydrogen in asecond hydrocracking unit to produce a secondary hydrocracked effluent.15. The process of claim 14, further comprising combining the secondaryhydrocracked effluent with the hydrocracked effluent to produce acombined hydrocracked effluent and separating the combined hydrocrackedeffluent into the upgraded lesser-boiling effluent, the middledistillate effluent, and the greater-boiling effluent.
 16. A process forupgrading a hydrocarbon feed with the system of claim 1, the processcomprising: introducing the hydrocarbon feed to the hydrotreating unitof the system of claim 1, where: the hydrocracked effluent separationsystem comprises a high pressure separator and a fractionator downstreamof the high pressure separator; and the adsorption unit is disposedbetween the high pressure separator and the fractionator; hydrotreatingthe hydrocarbon feed in the hydrotreating unit to produce a hydrotreatedeffluent; hydrocracking the hydrotreated effluent in the hydrocrackingunit to produce a hydrocracked effluent; passing the hydrocrackedeffluent to the high pressure separator that separates the hydrocrackedeffluent into light gases and a high pressure separator liquid effluent,where a high pressure separator liquid effluent comprises asphaltenes,coke precursors, or both; adsorbing at least a portion of theasphaltenes in the adsorption unit, coke precursors, or both, from the ahigh pressure separator liquid effluent; and passing the high pressureseparator liquid effluent from the adsorption unit to the fractionatorthat separates the high pressure liquid effluent to produce the upgradedlesser-boiling effluent and the greater-boiling effluent.